1. A method for predicting strength anisotropy in subsurface formations along a wellpath comprising:
receiving a stress model of the subsurface formation in the area of the wellpath;
obtaining bulk strength properties of target rock, wherein the bulk strength properties are determined without coring the
subsurface strata of interest for the target rock and without performing laboratory strength measurements of the target rock;

developing anisotropic failure criteria based on the bulk strength properties, wherein the anisotropic failure criteria are
developed using predictive algorithms that relate strength measurements derived from orientated core testing of samples not
from the subsurface strata of interest and the degree of strength anisotropy associated with diverse geologic planes of weakness;

combining the stress model with the anisotropic failure criteria to develop an anisotropic wellbore stability model which
calculates planes of weakness for the target rock; and

using the anisotropic wellbore stability model to enhance hydrocarbon recovery.

1. A method for pyrolyzing organic matter in a subterranean formation, the method comprising:
powering a first generation in situ resistive heating element within an aggregate electrically conductive zone at least partially
in a first region of the subterranean formation by transmitting an electrical current between a first electrode and a second
electrode of a first electrode pair in electrical contact with the first generation in situ resistive heating element to pyrolyze
a second region of the subterranean formation, adjacent the first region, to expand the aggregate electrically conductive
zone into the second region, wherein the expanding creates a second generation in situ resistive heating element within the
second region; and

powering the second generation in situ resistive heating element by transmitting an electrical current between a first and
a second electrode of a second electrode pair in electrical contact with the second generation in situ resistive heating element
to generate heat with the second generation in situ resistive heating element within the second region, wherein the first
electrode of the second electrode pair extends within the second region, and the second electrode of the second electrode
pair is the first electrode of the first electrode pair or the second electrode of the first electrode pair.

14. A method, comprising:
combusting a fuel with an oxidant and an exhaust gas in a combustion portion of a turbine combustor to generate combustion
products;

driving a turbine with the combustion products from the turbine combustor;
expanding and cooling the combustion products from the turbine through an exhaust passage in an exhaust section;
routing a cooling gas from a fluid supply system to the exhaust section, wherein the cooling gas comprises an extracted exhaust
gas, a gas separated from the extracted exhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides, or a combination thereof,
and the cooling gas comprises less than 10000 parts per million by volume (ppmv) of oxygen;

routing the cooling gas from the fluid supply system to an inner shroud cavity of the exhaust section through a manway of
the exhaust section; and

routing the cooling gas from the inner shroud cavity to the exhaust passage through one or more openings of the manway.

1. A method for generating a discretized physics-based model of a subsurface region having a shape, the method comprising:
selecting a pre-solved model related to at least a majority by volume of the subsurface region to be modeled by the discretized
physics-based model;

applying a solution of potential field lines to the pre-solved model to create a mesh the pre-solved model, the mesh including
a first set of domain boundaries and the mesh and the pre-solved model forming an intermediate model;

defining the shape of the subsurface region to be modeled by the discretized physics-based model, the shape including a second
set of domain boundaries representing subsurface features not reflected in the intermediate model such that the first set
of domain boundaries of the intermediate model is not fully aligned with the shape of the subsurface region represented by
the second set of domain boundaries; and

using a computer processor accessing non-transitory computer processor-readable medium to transform the domain boundaries
of the intermediate model to the shape of the subsurface region represented by the second set of domain boundaries of the
subsurface region by stretching the mesh of the intermediate model to the shape of the subsurface region defined by the second
set of domain boundaries to generate the discretized physics-based model, wherein at least a majority by number of intersections
of orthogonal elements within the intermediate model retain orthogonality within 75-105 degrees in the discretized physics-based
model.

1. A method for modeling hydraulic fractures in ductile rocks, comprising:
generating, on a computer, a constitutive model for a quasi-brittle material that incorporates unified creep-plasticity (UCP)
based on viscoplasticity theory;

performing, on a computer, a finite element analysis using the constitutive model, wherein performing the finite element analysis
comprises predicting a J-integral value and a stress field that incorporates a plasticity effect from finite element analysis
using the constitutive model;

determining, on a computer, an effective fracture propagation property for the quasi-brittle material based at least in part,
upon a result from the finite element analysis;

predicting, on a computer, hydraulic fractures in the quasi-brittle material, wherein predicting hydraulic fractures in the
quasi-brittle material comprises predicting a hydraulic fracture of the ductile rocks using a pore pressure cohesive zone
model (CZM); and

harvesting hydrocarbon from the fractured rock.

1. A combustor system, comprising:
a combustor having a first end, a second end, an outer shell, an inner shell, a secondary inner shell, and an annular volume
formed between the outer shell and the inner shell extending from the first end to the second end;

a carbon dioxide inlet configured to introduce carbon dioxide to the combustor;
an oxygen inlet configured to introduce oxygen to the combustor;
a first mixing zone disposed within the combustor and configured to mix a first portion of any carbon dioxide introduced through
the carbon dioxide inlet with at least a portion of any oxygen introduced through the oxygen inlet to produce a first mixture
within the first mixing zone comprising oxygen and carbon dioxide, wherein:

the first portion of any carbon dioxide introduced through the carbon dioxide inlet flows through the annular volume of the
combustor toward the first end of the combustor from the second end of the combustor,

the oxygen inlet is positioned in the annular volume and configured to promote mixing of the first portion of any carbon dioxide
introduced through the carbon dioxide inlet and the oxygen introduced through the oxygen inlet, and

the secondary inner shell is configured to prevent introduction of the oxygen introduced through the oxygen inlet through
the inner shell;

a fuel inlet configured to introduce a fuel into the first end of the combustor;
a second mixing zone disposed within the combustor and configured to mix the first mixture and the fuel to produce a second
mixture within the second mixing zone comprising oxygen, carbon dioxide, and fuel; and

a combustion zone configured to combust the second mixture to produce a combustion product, wherein a second portion of any
carbon dioxide introduced through the carbon dioxide inlet flows through one or more apertures disposed through the inner
shell and mixes with and cools the combustion product.

1. An apparatus for nuclear magnetic resonance examination of a thin sample in a static magnetic field, comprising at least
one coil comprising at least one wire path adapted to carry a controllable electric current and routed to define a plurality
of continuous figure eight double loops, wherein:
each loop in each double loop comprises an array wire element and a return wire portion;
the array wire elements in each loop are disposed substantially coplanar and substantially parallel;
the plurality of double loops are arranged so that the current in all the array wire elements flows in the same coordinate
direction whereby the array wire elements define a coil array for generating a magnetic field, substantially uniform in direction
and strength, generally parallel to an imaginary plane containing the coil array; and

when the sample is oriented so that the static field is normal to a plane of the sample, the at least one coil is disposable
parallel to a plane of the sample so that the direction of the magnetic field generated by the coil is substantially perpendicular
to the static field.

1. A feedwell system for delivering a slurry to a separation vessel, the system comprising:
a feedwell barrel for containing and controlling the slurry, the feedwell barrel having an inlet for receiving the slurry;
a series of spaced-apart internal baffles around an inner perimeter of the feedwell barrel for dissipating inflow energy while
limiting an internal circulation field within the feedwell barrel;

the feedwell barrel having a bottom with an outlet in the bottom to allow discharge of the slurry, the outlet being sized
to cause a buildup of the slurry within the feedwell barrel, to dissipate energy;

an extension downpipe depending down from the bottom of the feedwell barrel below the outlet for encouraging axi-symmetric
discharge of the slurry out of the extension downpipe;

a deflector plate below, and spaced from, the extension downpipe to deflect the slurry radially and outwardly; and
a protector plate above the deflector plate and below the extension downpipe for limiting discharge flow off the deflector
plate from disrupting layers formed in the separation vessel, for encouraging circumferential distribution, and for limiting
recirculation of the slurry into an area between the extension downpipe and the deflector plate, the protector plate comprising
at least one ventilation opening for limiting formation of an adverse pressure gradient and decelerating the flow of the slurry
from the feedwell barrel to the an inlet area between the deflector plate and the protector plate by allowing a controlled
inflow of an external fluid through the at least one ventilation opening into the inlet area between the deflector plate and
the protector plate.

1. A method of recovering heavy oil from a subterranean reservoir, the method comprising:
carrying out a steam-utilizing heavy oil recovery process to recover heavy oil from the subterranean reservoir while employing
a steam/solvent mixture for said steam-utilizing heavy oil recovery process instead of steam alone,

wherein solvent used in said steam/solvent mixture is a tailored solvent obtained from a precursor mixture of hydrocarbon
compounds by removing light end hydrocarbon compounds from said precursor mixture.

1. A method for summarizing data corresponding to at least one property of interest on an unstructured grid that includes
a plurality of active cells and a plurality of inactive cells on an output surface, the method comprising:
identifying an aggregation direction through a region of interest of the unstructured grid;
identifying at least one active cell along the aggregation direction;
summarizing data corresponding to the at least one property of interest for the at least one active cell;
constructing, using a computer system, an output surface based on model topologies represented by the unstructured grid or
an intersection of a surface and the unstructured grid;

assigning, using the computer system, an aggregated value for the at least one property of interest to a face of the output
surface on a line along the aggregation direction based at least in part on the data corresponding to the at least one property
of interest for the at least one active cell;

identifying at least one data hole in the output surface where at least one aggregation has no corresponding face on the output
surface, or where at least one output face is not assigned an aggregated value because it is not on the line along the aggregation
direction; and

filling, using the computer system, the at least one data hole by identifying at least one face associated with an inactive
cell on the line along the aggregation direction and assigning it an aggregated value or by identifying at least one face
on the output surface that is not assigned an aggregated value and assigning it an aggregated value corresponding to another
face in the cell containing the at least one face that is not assigned an aggregated value.

1. A computer implemented method for migrating 2D or 3D seismic data to obtain an image of a subsurface region comprising
sediment and a geo-body, said geo-body having a top and a base but being of uncertain location and dimensions, said method
comprising:
(a) deriving a sediment velocity model and using it to determine the geo-body top;
(b) from the seismic data, using illumination inside the geo-body to generate, using a computer, at least two of PP, PS, SP
and SS images of the geo-body base, using elastic imaging conditions and a selected velocity model for inside the geo-body;

(c) updating the sediment velocity model below the geo-body as it is now defined in (a) and (b); and
(d) performing elastic or acoustic migration, using the updated sediment velocity model from (c) and the geo-body velocity
model from (b), to form a final image of the subsurface region.

1. A method of preparing a petroleum sample having an inorganic contaminant species for use with one or more of elemental
and isotopic signature analysis, comprising:
(a) adding a first demulsifier to the petroleum sample, said first demulsifier having a known concentration of a specified
hydrocarbon-soluble elemental species referred to as a species of interest;

(b) separating the petroleum sample into one or more intermediate organic fractions and one or more inorganic fractions;
(c) mixing the one or more intermediate organic fractions with (i) a solvent in which the inorganic contaminant species is
soluble and the solvent has a known concentration of the species of interest, and (ii) a second demulsifier having a known
concentration of the species of interest;

(d) separating the one or more intermediate organic fractions into one or more prepared organic fractions and one or more
solvent-based fractions; and

(e) determining at least one of an elemental signature and an isotopic signature from the one or more prepared organic fractions.

1. A system for explosive fracturing of a reservoir, comprising:
a squash head charge;
a frame configured to orient the squash head charge towards a rock face in a wellbore in the reservoir;
an internal electrical bus coupled to the squash head charge, wherein the internal electrical bus is configured to carry an
ignition signal to a primer charge to detonate the squash head charge;

a controller coupled to the internal electrical bus; and
a cable connecting the controller to a surface through the wellbore, wherein the cable is configured to carry a signal to
the controller to trigger the ignition signal.

2. A method of removing a drilling assembly from a wellbore, wherein the drilling assembly includes a transition region between
a first section including a first cross-sectional area and a second section including a second cross-sectional area, wherein
the first cross-sectional area is less than the second cross-sectional area, wherein the first section is farther from a terminal
end of the drilling assembly than the second section, and further wherein the drilling assembly includes a fluid conduit configured
to transmit a drilling fluid stream, the method comprising:
withdrawing at least a portion of the drilling assembly from the wellbore;
detecting a variable associated with packoff within the wellbore; and
providing a fluidizing stream to a portion of a cuttings bed proximal the transition region, wherein the fluidizing stream
includes a portion of the drilling fluid stream, and further wherein the providing includes selectively providing the fluidizing
stream based at least in part on the variable associated with packoff.

1. A mine tailings dewatering assembly, comprising:
a mixing unit that is configured to receive a mine tailings slurry, which includes mine tailings, water, and a water-absorbing
polymer, to combine the mine tailings slurry with the water-absorbing polymer, and to generate an augmented mine tailings
slurry therefrom, wherein the mixing unit includes at least one of a transfer pipe, a static mixer, and a stirred tank;

a separation assembly configured to receive the augmented mine tailings slurry, which includes the mine tailings, the water,
and a swollen water-absorbing polymer, and to separate the swollen water-absorbing polymer from the augmented mine tailings
slurry to produce a dewatered mine tailings slurry; and

a water-absorbing polymer regeneration unit configured to receive the swollen water-absorbing polymer, to at least partially
release water from the swollen water-absorbing polymer, and to produce a regenerated water-absorbing polymer therefrom.

1. A gas turbine combustor, comprising:
a combustor comprising a partially perforated combustion liner;
an oxidant injection port configured for injection of an oxidant through the partially perforated combustion liner such that
the oxidant is injected proximate to a flame in the combustor;

a recycle-gas extraction port configured for an extraction of a recycle gas from the combustor, wherein the partially perforated
combustion liner allows a portion of the recycle gas to mix with at least a portion of an exhaust gas; and

a barrier to prevent mixing of the recycle gas and the oxidant prior to introduction of the oxidant through the partially
perforated combustion liner.

1. A method for inferring one or more physical property parameters of a subsurface media by inverting converted wave data
acquired during a seismic survey, comprising:
generating a composite seismic trace at a plurality of survey azimuths, said composite traces being composed such that their
amplitudes are free of effects of subsurface anisotropy; and

inverting at least one composite seismic trace by isotropic inversion to determine a property parameter of the subsurface
media.

1. A method for constructing a fully-sampled monitor survey, the method comprising:
obtaining a fully sampled base data set of a subsurface region at a first time;
obtaining a sparsely sampled monitor data set for the subsurface region at a second time, wherein the sparsely sampled monitor
data set is a data set for which the sampling at acquisition was less dense than in the fully sampled base data set;

transforming, using a computer, the obtained fully sampled base data set from a first domain into a second domain;
determining a change to the transformed fully sampled base data set that, when inverse transformed, reproduces the obtained
sparsely sampled monitor data set at locations where the sparsely sampled monitor data set was recorded;

modifying the transformed fully sampled base data set in the second domain by the determined change to generate a modified
base data set;

inverse transforming the modified base data set into the first domain to generate a fully sampled monitor data set for the
subsurface region as it exists at the second time; and

processing the generated fully sampled monitor data set to compute a three-dimensional (3D) representation of the subsurface
region as it exists at the second time, wherein the 3D representation comprises a 3D image.

1. A method of drilling a wellbore through subterranean formation, the method comprising:
(a) receiving data regarding at least two drilling operational parameters related to wellbore drilling operations into an
operating parameter database;

(b) computing a mathematical objective function based upon the received data for input into each of a global search engine
and a local search engine;

(c) inputting the computed objective function and received data into the global search engine to create a global response
surface, and to identify at least two global-engine recommended drilling parameters;

(d) inputting the computed objective function and received data into the local search engine to determine a significantly
correlated drilling parameter, and to identify at least two local-engine recommended drilling parameters based upon the significantly
correlated controllable drilling parameter;

(e) creating a combined dataset using a data fusion process by combining (i) the created global response surface, and (ii)
the determined significantly correlated controllable drilling parameter and the local-engine recommended drilling parameters;

(f) using a decision tree process on the data fusion combined dataset to determine whether to define a status mode of the
combined dataset as at least one of a learning mode and an application mode;

(g) wherein if the decision tree status mode determination of step (f) is learning mode, then;
a. providing an additional data input for each of the at least two drilling operational parameters in the operating parameter
database and repeating steps (b)-(f) for the additional data input for expanding the created global response surface and for
revising the global-engine recommended drilling parameters; and

b. recommending use of the global-engine recommended drilling parameters for making an implementable drilling operational
decision; and

(h) wherein if the decision tree status mode selection of step (f) is application mode, then comparing the global-engine recommended
drilling parameters with the local-engine recommended drilling parameters;

a. wherein if the compared global-engine recommended drilling parameters and the local-engine recommended drilling parameters
are determined to be correlated within a predefined range of agreement with each other, instructing to use either of the global-engine
recommended or local-engine recommended set of correlated drilling parameters for use regarding drilling operations; and

b. wherein if the two sets are determined not within a predefined range of agreement with each other, re-perform the local
search engine on the global-engine recommended drilling parameters to identify updated local-engine recommended drilling parameters,
and instructing to use the local-engine recommended set of correlated drilling parameters for use regarding drilling operations.

31. A system for analyzing isotope variations in inhomogeneous matrices, comprising:
an ion generator, wherein the ion generator is configured to generate ions from a target region of a sample;
a particle detector, wherein the particle detector is configured to generate a signal that is proportional to the number of
isotopes for a target element in the target region; and

an analysis unit, comprising:
an input system configured to process the signal from the particle detector to determine a count for two or more isotopes
for the target element;

a processor; and
a memory device comprising code configured to direct the processor to:
calculate an isotope ratio for the target element;
project the isotope ratio onto a matrix corrected calibration curve,
wherein the matrix corrected calibration curve comprises:
selecting a plurality of matrix standards that have matrices that have a common characteristic with the sample;
running a bulk isotope analysis on each of the plurality of matrix standards to determine a bulk isotope ratio value for each
of the plurality of matrix standards;

running a plurality of microprobe analyses on each of the plurality of matrix standards to determine a plurality of microprobe
isotope ratio values for each of the plurality of matrix standards;

eliminating spurious values from the plurality of microprobe isotope ratio values;
averaging the plurality of microprobe isotope ratio values for each of the plurality of matrix standards to create an average
microprobe isotope ratio value associated with each of the plurality of matrix standards;

plotting the bulk isotope ratio value for each of the plurality of matrix standards against the average microprobe isotope
ratio value associated with each of the plurality of matrix standards to create the matrix corrected calibration curve; and

determine a matrix corrected value for the isotope ratio.

1. A hydrocarbon processing method comprising:
processing a gaseous hydrocarbon stream to form a first production stream and a first injection stream; and
compressing the first injection stream in a compressor placed at a selected location below a surface of a sea;
wherein the location of the subsea compressor relative to a nearest inhabited area is determined based on a bubble plume trajectory
of a model leak of the first injection stream from the compressor; and

wherein the bubble plume trajectory is determined using one or more crossflow momentum parameters.

1. A tool assembly for performing a tubular operation in a wellbore, comprising:
an actuatable tool;
a location device for sensing the location of the actuatable tool within a tubular body based on a physical signature provided
along the tubular body;

diversion materials;
a friable container for holding the diversion materials, the container being part of the autonomous unit of the tool assembly
and being designed to release the diversion materials in response to a command from the on-board controller proximate and
in anticipation of the time of a perforating gun being fired; and

an on-board controller configured to send an actuation signal to the tool when the location device has recognized the selected
location of the tool based on the physical signature and tool velocity and to determine when to send the actuation signal
to actuate the tool, wherein:

the actuatable tool, the location device, and the on-board controller are together dimensioned and arranged to be deployed
in the tubular body as an autonomously actuatable unit; and

the actuatable tool is designed to be autonomously actuated to perform the tubular operation in response to the actuation
signal; and

the actuatable tool assembly is friable such that when destructed it becomes small enough pieces to not impede ongoing operations.

1. A computer-implemented method for estimating missing near-offset traces in measured seismic data, comprising relating all
or part of synthetic seismic data, generated using a reference subsurface model, to the measured seismic data by a reciprocity
relationship, and then iteratively inverting the reciprocity relationship for the missing near-offset traces using a programmed
computer, followed by using the estimated missing near-offset traces to augment the measured seismic data, then applying a
technique for removal of multiple reflections, then interpreting the seismic data with multiple reflections removed for indications
of accumulations of hydrocarbons, and in the event of such an indication at a location, drilling a well at the location and
producing hydrocarbons.

1. A method of recovering oil from a viscous oil reservoir, the method comprising:
receiving electrical power from an electrical grid which is fed by at least one fluctuating electricity supply;
generating steam by heating water within a first fluid stream with an electrical heater that is powered by at least a portion
of the received electrical power;

adjusting a heat output from the electrical heater to at least partially correspond with an estimated excess power supply
on the electrical grid;

generating steam by heating water within a second fluid stream with fired-heater;
adjusting a heat output from the fired-heater to at least partially compensate for fluctuations in the electrical heater heat
output;

injecting the steam generated from the first fluid stream, the second fluid stream, or mixtures thereof over time into a viscous
oil reservoir to mobilize the viscous oil; and

producing mobilized oil from the viscous oil reservoir;
wherein the fired-heater and the electrical heater are within a common vessel in a surface facility.

1. A feed delivery system for use with a froth separation unit, the system comprising:
at least one feed delivery pipe for delivering and conditioning the feed into the froth separation unit through one or more
side inlets in a side wall of the froth separation unit; and

a flow conditioning system, within the at least one pipe, for flow conditioning solvent-treated bitumen froth to a side-inlet
Richardson number of equal to or greater than 1.0, the froth comprising bitumen, water, precipitated asphaltene aggregates,
and mineral solids;

wherein the flow conditioning system comprises a perforated sparger and a perforated plate, the perforated sparger being upstream
of the perforated plate.

1. A method for completing a wellbore in a subsurface formation, the method comprising:
providing a sand control device comprising:
an elongated base pipe having at least two joints,
at least one alternate flow channel extending substantially along the base pipe, and
a filter medium radially surrounding the base pipe along a substantial portion of the base pipe so as to form a sand screen;
providing a packer assembly comprising at least one mechanically-set packer, each mechanically-set packer comprising:
a sealing element,
an inner mandrel, and
at least one alternate flow channel;
connecting the packer assembly to the sand screen intermediate the at least two joints so that the at least one alternate
flow channel in the packer assembly is in fluid communication with the at least one alternate flow channel in the sand control
device;

running the sand control device and connected packer assembly into the wellbore;
setting the at least one mechanically-set packer by actuating the sealing element into engagement with the surrounding wellbore;
injecting a gravel slurry into the wellbore in order to form a gravel pack above and below the packer assembly after the at
least one mechanically-set packer has been set;

running a string of tubing into the wellbore with an elongated isolation string connected at a lower end of the string of
tubing, the isolation string comprising:

a tubular body having an inner diameter defining a bore in fluid communication with a bore of the string of tubing, and an
outer diameter configured to be received within the base pipe and the inner mandrel,

a first valve providing fluid communication between the bore of tubular body and an annular region formed between the outer
diameter of the tubular body and the surrounding base pipe, and

one or more seals along the outer diameter of the tubular body;
placing the elongated isolation string within the base pipe and across the packer assembly such that:
the first valve is above or below the packer assembly, and
the one or more seals is adjacent to the set packer assembly; and
activating the one or more seals in order to seal an annular region formed between the outer diameter of the tubular body
and the surrounding inner mandrel adjacent to a set packer.

26. A method for stimulating a multi-zone wellbore, the wellbore being completed with a string of production casing in a substantially
vertical orientation, and the method comprising:
creating a first set of perforations in a first zone of interest and another set of perforations in a second zone of interest;
thereafter pumping a first volume of acidic fluid into the wellbore;
dropping a fluid diversion plug into the wellbore, the fluid diversion plug having a defined geometry, and being fabricated
from a material that dissolves in the presence of the first volume of acidic fluid over a selected period of time;

pumping a second volume of acidic fluid into the wellbore in order to push the fluid diversion plug down the wellbore and
to cause at least a portion of the first volume of acidic fluid to travel into the first zone of interest along the production
casing;

setting the fluid diversion plug along the production casing above the first zone of interest to inhibit the flow of the second
volume of acidic fluid into the first zone of interest;

injecting at least a portion of the second volume of acidic fluid into the second zone of interest along the production casing
and above the fluid diversion plug before the fluid diversion plug substantially dissolves;

dropping a fluid displacement plug into the wellbore, the fluid displacement plug also having a defined geometry, and being
fabricated from a material that dissolves in the presence of the second volume of acidic fluid over the selected period of
time; and

pumping a third volume of fluid into the wellbore in order to push the fluid displacement plug down the wellbore and to at
least partially inject the second volume of acidic fluid into the second zone of interest above the first zone of interest.

1. A hydrocarbon prospecting method for forming an N-dimensional model of a physical property for a subsurface region comprising:
obtaining geophysical survey data from a subsurface region, wherein the data are sensitive to a physical property;
constructing an initial model of the physical property in the subsurface region by performing a less than N-dimensional stochastic
inversion of the data;

performing, using a computer, an N-dimensional deterministic inversion of the data using the initial model as a starting model,
thereby forming the N-dimensional model of the subsurface region, said N-dimensional model including hydrocarbon deposits;

using the N-dimensional model to generate, with a computer, an image of the subsurface region for exploration of hydrocarbons;
and

exploring for hydrocarbons using the image of the subsurface region.

1. A method associated with the production of hydrocarbons using tubular member comprising threaded connections, the method
comprising:
determining constituents of an evaluation group of threaded connections the constituents comprising a first plurality of the
threaded connections and a second plurality of the threaded connections;

conducting physical testing on each constituent of the first plurality of the threaded connections at a plurality of test
conditions to test connection performance of the tested constituent at each of the plurality of tested load and pressure test
conditions, producing a first plurality of tested connection performance results;

performing modeling analysis on each constituent of the first plurality of threaded connections at a plurality model conditions
to determine a modeled connection performance factor for each of the modeled plurality of modeled conditions, producing a
first plurality of modeled connection performance factors for each modeled constituent of the first plurality of threaded
connections;

comparing for each constituent the first plurality of tested connection performance results and the first plurality of modeled
connection performance factors to determine a characteristic performance factor for each constituent of the first plurality
of threaded connections;

comparing each of the determined characteristic performance factor for each constituent of the first plurality of threaded
connections with each other to determine a first plurality constituent group characteristic performance factor;

performing modeling analysis on each constituent of the second plurality of threaded connections at a plurality of model conditions
to determine a second plurality modeled connection performance factor for each of the plurality of modeled conditions, producing
a second plurality of modeled connection performance factors for each modeled constituent of the second plurality of threaded
connections;

applying the first plurality constituent group characteristic performance factor to the second plurality of threaded connection
constituents to define an acceptable range of performance limits for at least one of the second plurality of threaded connections;

obtaining tubular members from the constituents based upon the defined acceptable range of performance limits obtained in
the evaluation of the threaded connections;

installing the obtained tubular members within a wellbore; and
producing a formation fluid from the wellbore containing the tubular members.

1. A method for detecting hydrocarbons with an underwater vehicle equipped with measurement components comprising:
deploying an underwater vehicle (UV) into the body of water;
performing an operation stage that comprises:
navigating the UV within the body of water based on satellite and/or airborne sensing data that indicate a hydrocarbon slick;
monitoring the body of water with measurement components associated with the UV to collect measurement data, wherein the measurement
components comprise a mass spectrometer and fluorometer; and

determining the concentrations of chemical components with the mass spectrometer and fluorometer;
retrieving the UV upon completion of the operation stage; and
collecting data from the UV to determine whether hydrocarbons are present and the location.

1. A method of drilling a wellbore through subterranean formation, the method comprising:
(a) receiving data regarding at least two drilling operational parameters related to wellbore drilling operations into an
operating parameter database;

(b) computing a mathematical objective function based upon the received data for input into each of a global search engine
and a local search engine;

(c) inputting the computed objective function and received data into the global search engine to create a global response
surface, and to identify at least two global-engine recommended drilling parameters;

(d) inputting the computed objective function and received data into the local search engine to determine a significantly
correlated drilling parameter, and to identify at least two local-engine recommended drilling parameters based upon the significantly
correlated controllable drilling parameter;

(e) creating a combined dataset using a data fusion process by combining (i) the created global response surface, and (ii)
the determined significantly correlated controllable drilling parameter and the local-engine recommended drilling parameters;

(f) using a decision tree process on the data fusion combined dataset to determine whether to define a status mode of the
combined dataset as at least one of a learning mode and an application mode;

determining operational updates to at least one of the at least two controllable drilling parameters based at least in part
on the further optimized recommendation; and

implementing at least one of the determined operational updates in the wellbore drilling operations.

1. A method for exploring for hydrocarbons, comprising:
obtaining 3D data sets of at least two different types of geophysical data, each representing a common subsurface region;
using a computer to perform separate 3D inversions of each data type to obtain a 3D model each of a corresponding physical
property for each data type;

using a computer to synthesize a 1D response of each 3D model at one or more selected (x,y) locations to obtain 1D datasets
that each conform to a 1D expression of a different 3D model of one of the at least two different types of geophysical data;
and

using a computer to jointly invert the 1D datasets, each of which was synthesized from different 3D models, which correspond
to the at least two different types of geophysical data, respectively, at each selected (x,y) location and analyzing results
for presence of hydrocarbons.

1. A computer-implemented method for analyzing a volume composed of voxels of seismic data representing a subsurface region
for presence of a hydrocarbon system or a particular play, comprising:
partitioning the seismic data volume to form a plurality of segments;
computing a prospectivity score for each voxel, wherein at least two elements are selected, and for each element at least
one seismic attribute is selected, and then an element score is calculated for each selected element based on the selected
at least one seismic attribute, and the prospectivity score is formed by combining the element scores;

ranking the plurality of segments for presence of a hydrocarbon system or the particular play based at least partly on the
prospectivity scores for the voxels of seismic data in each segment; and

wherein the elements are selected from a group consisting of reservoir, seal, trap, source, charge, overburden, maturation,
migration, accumulation, and timing, or juxtaposition or coexistence of any two or more of them.

1. A method for generating a cement density image in a cemented borehole, comprising:
positioning a logging tool inside the borehole at a selected depth, wherein the logging tool comprises a gamma ray source,
a short-spaced detector positioned ?7 inches from the source, and a long-spaced detector positioned less than 12 inches but
farther than the short-spaced detector from the source; and

measuring gamma ray count rates at each detector and using them to calculate an estimated cement thickness or density.

1. A method for forming carbon allotropes, comprising:
treating a carbonaceous compound to form a feedstock comprising at least about 10 mol % oxygen, at least about 10 mol % carbon,
and at least about 20 mol % hydrogen;

heating, via a heat exchanger, the feedstock with waste heat from a waste gas stream;
forming carbon allotropes from the feedstock in a reactor in a Bosch reaction at a temperature of at least about 500° C.;
separating, via a separator vessel disposed downstream of the reactor, the carbon allotropes from a reactor effluent stream,
forming the waste gas stream having waste heat from the reactor;

passing the waste gas stream through the heat exchanger to an ambient-temperature heat exchanger to condense water in the
waste gas stream to give a dry waste gas stream; and

passing the dry waste gas stream to a fractionation system comprising a separation column.

1. A gas processing facility for processing a hydrocarbon gas stream comprising sulfurous components and carbon dioxide, the
gas processing facility comprising:
an acid gas removal facility for separating the hydrocarbon gas stream into (i) a sweetened gas stream, and (ii) a first acid
gas stream comprised primarily of hydrogen sulfide and carbon dioxide;

a sulfur recovery unit for receiving the first acid gas stream, and separating the first acid gas stream into (i) a liquid
stream of elemental sulfur, and (ii) a tail gas comprising acid gas impurities;

a tail gas treating unit having a reducing gas generator and a catalytic bed to hydrogenate the tail gas, an absorber vessel,
and a solvent regenerator vessel, where the tail gas treating unit receives the tail gas and separates the tail gas into (i)
an overhead by-products stream from the absorber vessel, and (ii) a second acid gas stream from the regenerator vessel, where
the second acid gas stream is a carbon dioxide-rich gas stream; and

a compressor station for receiving the second acid gas stream from the regenerator vessel, and providing pressure to the second
acid gas stream for injection into a subsurface reservoir.

1. A computer-implemented method for analyzing a volume of seismic or seismic attribute data, either being referred to as
“the seismic data volume,” to discover spatial location and shape of geologic features of a subsurface region, comprising:
making a tensor representation of the seismic data volume, and then grouping the data by a tensor voting method, wherein components
of a tensor are computed, using a computer, to represent each of a plurality of selected spatial points, called tokens, in
the seismic data volume;

making, with a computer, connections between tokens based on the tensor voting but also on a binary polarity attribute;
generating, with a computer, a visualization of the connections between the tokens in order to discover spatial location and
shape of geologic features of the subsurface region; and

using the visualization of the connections between the tokens to locate hydrocarbons within the subsurface region.

1. A method of treating a gaseous feed stream, comprising:
providing a gaseous feed stream having a volume of oil therein;
treating a portion of the gaseous feed stream using a selective component removal system having at least one swing adsorption
process unit to form a utility stream for use in a utility component, wherein the at least one swing adsorption unit includes
a structured adsorbent bed comprising a high surface area solid and configured to remove at least a portion of the volume
of oil and the portion of the gaseous feed stream is at a pressure from at least about 100 bar to at least about 500 bar;

regenerating the swing adsorption process unit in a calcination process;
feeding the utility stream into the utility component, wherein the utility stream is compatible with the utility component
and wherein the utility stream is a dry seal gas; and

utilizing the utility stream in the utility component.

1. A method for installing a subsea equipment protection system into a seabed soil comprising:
determining an ice gouge depth at a seafloor location;
providing a suction caisson system comprising a caisson body, a detachable cover and a pump constructed and arranged to deliver
fluid to and from the interior of the caisson body;

positioning the caisson body at the seafloor location;
operating the pump to apply a suction force thereby embedding the caisson body into the seabed soil;
removing the detachable cover;
excavating a portion of the seabed soil located inside the caisson body; and
installing subsea equipment inside the caisson body, wherein the caisson body has a weakened section located between an upper
end and a lower end of the caisson body, the weakened section having a first cross-sectional dimension, the caisson body having
a second cross-sectional dimension proximate the upper rim, and the first cross-sectional dimension is less than the second
cross-sectional dimension, and wherein the top of the subsea equipment is positioned below the weakened section.

18. A method for harvesting hydrocarbons from an oil sands reservoir, comprising:
drilling a horizontal well proximate to an impermeable section of a cap rock over the oil sand reservoir;
flowing a refrigerant through the horizontal well to freeze water proximate to the horizontal well, forming a freeze wall
in contact with the impermeable section of the cap rock, wherein the freeze wall isolates a permeable section of the cap rock
from the impermeable section of the cap rock;

flowing a gas into a chamber formed by the cap rock and the freeze wall to displace water from the chamber;
drilling at least one well through the oil sands reservoir;
injecting steam into the oil sands reservoir; and
producing fluids from the oil sands reservoir.

15. A method of processing a feed stream comprising:
a) passing a feed stream through a rotary valve assembly;
b) passing the feed stream from the rotary valve assembly to one of a plurality of reciprocating valve assemblies based on
the alignment of the rotary valve assembly;

c) processing the feed stream from the one of a plurality of reciprocating valve assemblies in an adsorbent bed unit dedicated
to the one of a plurality of reciprocating valve assemblies to separate one or more contaminants from the feed stream to form
a product stream;

d) conducting away from the adsorbent bed unit the product stream;
e) rotating one or more components in the rotary valve assembly to a subsequent alignment, wherein the subsequent alignment
stops fluid flow to the one of a plurality of reciprocating valve assemblies from the rotary valve assembly and permits fluid
flow to a subsequent one of the plurality of reciprocating valve assemblies;

f) processing the feed stream from the subsequent one of a plurality of reciprocating valve assemblies in a subsequent adsorbent
bed unit dedicated to the subsequent one of a plurality of reciprocating valve assemblies to separate one or more contaminants
from the feed stream to form a product stream; and

g) conducting away from the subsequent adsorbent bed unit the product stream; and
h) repeating the steps a-g for at least one additional cycle.

1. A coring system comprising:
a suction carrier comprising a body defining a cavity and a top portion having an aperture, the body having a length;
a pump positioned adjacent to the aperture and constructed and arranged to deliver a fluid into or from the cavity; and
a corer constructed and arranged to releasably engage with the suction carrier, the corer having a length greater than the
body length of the suction carrier such that when embedded within soil the corer extends to a greater depth than the suction
carrier.

12. A method of positioning a downhole assembly within a wellbore conduit, the method comprising:
conveying, with a fluid, the downhole assembly in a downhole direction and to a target region of the wellbore conduit, wherein
the downhole assembly includes a tool string and a drag-enhancing structure that includes a frangible drag-enhancing structure
body; and

decreasing a resistance to fluid flow past the downhole assembly while the downhole assembly is within the target region of
the wellbore conduit by destroying the frangible drag-enhancing structure body.

1. A marine hydrocarbon operations structure comprising:
a caisson body having a top surface which defines an opening, the caisson body is constructed and arranged to be positioned
proximate a seabed;

a shaft positioned within the opening, the shaft has an external surface and an interior, the shaft having an engagement member
positioned on the external surface of the shaft;

a lower jack house system constructed and arranged to change the vertical position of the shaft through interaction with the
engagement member; and

an operations platform supported by the shaft.

1. A method of identifying geological materials of interest comprising:
(i) providing a nanoprobe composition comprising one or more nanoprobes;
wherein the nanoprobe comprises:
(a) at least one tag; and
(b) at least one signal generator;
(ii) introducing the nanoprobes to a geological material; and
(iii) detecting the presence of a signal generated by the signal generator on association of the tag with a target.

1. A system for producing a liner for a pipe, the system comprising:
a source of material to form a body of the liner;
a source of material to form a monitoring sensor in the liner; and
a device that simultaneously receives the material to form the body of the liner and the material to form the monitoring sensor
in the liner and produces the body of the liner with the monitoring sensor embedded within the body of the liner in a single-step
process such that the body of the liner is composed of a single layer of material with the monitoring sensor placed between
an inner surface and an outer surface of the single layer.

1. A method of calibrating multiple electromagnetic radiation detectors within a detection system comprising:
generating a calibration electromagnetic radiation beam at a first temperature;
detecting at least a portion of the calibration electromagnetic radiation beam with a first electromagnetic radiation detector;
obtaining an average intensity value of a plurality of pixels of the first electromagnetic radiation detector detecting the
calibration electromagnetic radiation beam;

adjusting one or more pixels of the first electromagnetic radiation detector to decrease the difference between the intensity
of an individual pixel and the average intensity value of the first electromagnetic radiation detector;

detecting at least a portion of the calibration electromagnetic radiation beam with a second electromagnetic radiation detector;
and

adjusting one or more pixels of the second electromagnetic radiation detector to decrease the difference between the intensity
of an individual pixel and the average intensity value of the first electromagnetic radiation detector.

1. Apparatus for compressing fluids comprising:
a prime mover having at least one drive shaft mechanically coupled thereto;
a first compressor coupled to the prime mover via a first drive shaft;
a second compressor coupled to the prime mover via a second drive shaft;
a third compressor coupled to the prime mover via a third drive shaft;
a first conduit for connection to a source of fluid to be compressed;
a pair of parallel conduits each extending from the first conduit to respective inlets for any two of the three compressors;
a second conduit for connection to a source of fluid to be compressed, the second conduit having a pair of parallel conduits
each extending to a respective side load inlet of any two of the three compressors; and

a pair of parallel output conduits each extending from an outlet of the any two compressors, wherein the parallel output conduits
convey compressed fluids; and wherein the compressed fluids are directed through one or more compressed fluid conduits to
an inlet of the remaining compressor.

1. A method for acquiring seismic data in a body of water, said body of water being covered by ice or ice floes, comprising:
a) positioning a control station at or near an opening in the ice cover, said control station being a fixed structure or a
marine vessel;

b) deploying into the body of water under the ice or ice floes from said control station one or more ROV units, each said
ROV unit being an unmanned unit that remains tethered by an umbilical to said control station, said umbilical providing control
and power to the ROV unit under the ice or ice floes;

c) operating the one or more ROV units under the ice or ice floes to deploy towed seismic sensors and recording equipment
on or near the bottom of the body of water under the ice or ice floes;

d) operating the same or another of the one or more ROV units under the ice or ice floes to deploy seismic source equipment
on or near the bottom of the body of water under the ice or ice floes;

e) generating and applying control signals to one or more of the ROV units for transfer to the equipment of c) and d) to generate
and to record seismic signals;

f) operating the one or more ROV units within the water under the ice or ice floes to move the seismic source equipment and
seismic sensors and recording equipment to other locations, and to repeat c) through e) until completion.

1. A method for modeling dynamic systems, said method comprising:
constructing an input parameter space for a model of a geological system with a computer system, said input parameter space
including more than three dimensions, and said model associated with response data, wherein the input parameter space comprises
a plurality of input parameters that each has a range of values and said response data is generated from the model and one
or more of the plurality of input parameters;

representing said input parameter space visually, with said computer system, with fewer dimensions than a number of dimensions
of said input parameter space by using a subset of said response data;

conditioning said input parameter space to reduce a size of said input parameter space by using at least said subset of said
response data and measured data associated with said geological system, said conditioning comprising:

defining a constraint associated with said response data;
creating one or more regions around said response data that satisfies said constraint;
displaying said one or more regions in said visual representation of said input parameter space; and
narrowing one or more ranges of said plurality of input parameters based on the one or more regions; and
updating said representation of said input parameter space to visually represent said reduction of said input parameter space.

1. A system, comprising:
a turbine combustor, comprising a cap dividing an interior volume into a head end portion and a combustion portion;
a turbine driven by combustion products from the turbine combustor;
an exhaust gas compressor, wherein the exhaust gas compressor is configured to compress and route an exhaust gas from the
turbine to the turbine combustor;

a flow path from the exhaust gas compressor, through the turbine combustor, and into the turbine;
a hydrocarbon production system coupled to the exhaust gas compressor; and
a first catalytic converter disposed along the flow path, wherein a first catalytic converter is disposed within the combustion
portion of the turbine combustor.

1. A method of controlling a power plant that comprises a working fluid and a recirculation loop, wherein the power plant
includes a combustor operably connected to a turbine, and wherein the recirculation loop comprises a recirculation compressor,
the combustor positioned downstream of the recirculation compressor, the turbine positioned downstream of the combustor, and
a recirculation conduit configured to direct an outflow of the working fluid from the turbine to the recirculation compressor,
the method including the steps of:
recirculating at least a portion of the working fluid through the recirculation loop;
controlling the power plant such that the combustor at least periodically operates at a preferred stoichiometric ratio by
controlling an amount of a compressed oxidant supplied to the combustor at an oxidant input and an amount of a fuel supplied
to the combustor at a fuel input, wherein the recirculation loop is configured to prevent the input of the compressed oxidant
and the fuel to all locations except for the oxidant input and the fuel input, respectively, occurring in the combustor;

extracting the working fluid from a first extraction point and a second extraction point positioned on the recirculation loop
during periods when the combustor operates at the preferred stoichiometric ratio;

determining a characteristic of the working fluid at the first extraction point;
determining the characteristic of the working fluid at the second extraction point; and
based on the characteristic of the working fluid at the first extraction point and the characteristic of the working fluid
at the second extraction point, extracting the working fluid from both the first extraction point and the second extraction
point;

determining a preferred value for the characteristic of the working fluid based on an intended downstream application; and
controllably mixing the working fluid extracted from the first extraction point and the working fluid extracted from the second
extraction point such that a combined flow of extracted working fluid comprises the preferred value for the characteristic
of the working fluid.

1. A computer implemented method for estimating fluid heterogeneity in a subsurface region from compressional wave attenuation
or velocity dispersion, comprising:
measuring compressional wave attenuation or velocity, or extracting it from geophysical data, for at least one frequency;
selecting a frequency-dependent, mathematical rock physics model for attenuation or velocity, said model pertaining to or
containing one or more model parameters that pertain to heterogeneous features of fluid distribution in the subsurface region;

using the rock physics model to predict frequency dependence of compressional wave attenuation or velocity; and
using the predicted frequency dependence, the attenuation or velocity measured or determined from the geophysical data for
at least one frequency, and measured or estimated rock and fluid properties of the subsurface region, called subsurface properties,
to determine, using a computer, at least one unknown subsurface property, including fluid saturation, that is related to fluid
heterogeneity, each such subsurface property corresponding to a parameter in the mathematical rock physics model.

1. A computer-implemented geophysical prospecting method for producing a representation of a subsurface region from multi-dimensional
seismic data, comprising:
(a) using a cascade of filtering operations to decompose the seismic data into components in a frequency-wavenumber domain
wherein the data are represented in terms of tiled windows;

(b) applying one or more processing operations to the decomposed data, said processing operations being designed to enhance
a representation of the subsurface region from the seismic data;

(c) applying the filtering operations' adjoint operations to the decomposed data after the processing operations, then summing
data components weighted by normalization factors computed to produce a flat impulse response; and

(d) using the weighted and summed data from (c) to generate a representation of the subsurface region, and using the representation
for geophysical prospecting.

1. A method of actuating a downhole tool in a wellbore, the wellbore having casing collars that form a physical signature
for the wellbore, comprising:
acquiring a CCL data set from the wellbore, the CCL data set correlating recorded magnetic signals with measured depth, thereby
forming a first CCL log for the wellbore;

selecting a location within the wellbore for actuation of a wellbore device;
downloading the first CCL log into a processor on-board the downhole tool;
deploying the downhole tool into the wellbore such that the downhole tool traverses casing collars, the downhole tool comprising
the processor, a casing collar locator, and an actuatable wellbore device;

wherein the processor is programmed to:
continuously record magnetic signals as the downhole tool traverses the casing collars, forming a second CCL log;
transform the recorded magnetic signals of the second CCL log by applying a moving windowed statistical analysis, wherein
applying a moving windowed statistical analysis comprises (i) defining a pattern window size (W?) for sets of magnetic signal
values, and (ii) computing a moving mean m(t+1) for the magnetic signal values over time;

incrementally compare the transformed second CCL log with the first CCL log during deployment of the downhole tool to correlate
values indicative of casing collar locations;

recognize the selected location in the wellbore; and
send an actuation signal to the actuatable wellbore device when the processor has recognized the selected location; and
sending the actuation signal to actuate the downhole tool.

1. A combustion system, comprising:
a high concentration carbon dioxide (CO2) stream;

at least one CO2 flow regulation device configured to adjust an overall flow rate of the high concentration CO2 stream and split the high concentration CO2 stream into a primary diluent stream having a flow rate and a secondary diluent stream having a flow rate, wherein the at
least one CO2 flow regulation device is further configured to adjust the primary diluent stream flow rate independently of the overall flow
rate of the high concentration CO2 stream;

an oxygen supply stream having a flow rate;
at least one oxygen flow regulation device configured to adjust the oxygen supply stream flow rate;
a mixing device arranged to combine the primary diluent stream and the oxygen supply stream to form an oxygenation stream
having a flow rate and an oxygen to CO2 ratio;

a combustion fuel stream having a flow rate and a composition;
a combustor consisting of at least a primary combustion zone and a burnout zone, wherein the combustor is configured to mix
and combust the oxygenation stream and the combustion fuel stream within the primary combustion zone at a flame temperature
and a primary residence time sufficient to produce a hot products stream at about equilibrium conditions, and configured to
dilute the hot products stream with the secondary diluent stream within the burnout zone to form a combustion products stream
having a lower temperature than the hot products stream;

an expansion device configured to expand the combustion products stream to form an expanded products stream having a lower
temperature than the combustion products stream;

a control system, comprising:
a first controller configured to regulate the flow rate of the oxygen supply stream in proportion to the flow rate of the
combustion fuel stream so as to produce near stoichiometric combustion in the primary combustion zone; and

a second controller configured to regulate the oxygen to CO2 ratio of the oxygenation stream by controlling the primary diluent stream flow rate to produce a primary combustion zone flame
temperature configured to provide: an adequate margin between a combustor average velocity, a blow-off limit of the combustor,
and the primary residence time within the combustor sufficient to produce the combustion products stream at about equilibrium
conditions; and

at least one temperature sensor operatively connected to the control system and the at least one CO2 flow regulation device and configured to measure the temperature of the combustion products stream and send a signal to the
control system, which is configured to adjust the secondary diluent stream flow rate based on the temperature of the combustion
products stream to produce a desired temperature of the secondary combustion products stream at some location after an exit
of the combustion system;

at least one oxygen sensor located in the expanded products stream at a location spaced from the exit of the expansion device
configured to measure the amount of oxygen in the expanded products stream and send a signal to the control system, wherein
the control system is configured to adjust an oxygen to fuel ratio of oxygen in the oxygenation stream and fuel in the combustion
fuel stream to achieve a substantially stoichiometric combustion as indicated by a near zero oxygen content in the expanded
products stream and a measurable oxygen content in the expanded products stream if the oxygen proportion is increased by a
small amount; and

at least one load controller configured to control the flow rate of the combustion fuel stream to maintain a desired load
condition in the expansion device.

1. A system for stimulating a multi-zone well, comprising:
a tubular body dimensioned to be received within a wellbore, the tubular body being apportioned into at least a first zone
and a second zone;

a first set of plugs placed in pre-drilled holes along the tubular body within the first zone, the first set of plugs each
comprising a first retainer to secure the respective plug in the respective pre-drilled hole from an interior surface of the
tubular body, the first retainer being fabricated to dissolve upon contact with an acidic fluid within a first selected time
period to permit the first plug to disengage from the respective pre-drilled hole; and

a second set of plugs placed in pre-drilled holes along the tubular body within the second zone, the second set of plugs each
comprising a second retainer to secure the respective plug in the respective pre-drilled hole from an interior surface of
the tubular body, the second retainer being fabricated to dissolve upon contact with the acidic fluid within a second selected
time period that is greater than the first selected time period to permit the respective plug to disengage from the respective
pre-drilled hole.

1. A method for correcting measured data from a marine seismic survey to eliminate surface-related multiples, said measured
data being pressure data either measured by pressure sensor receivers located in the water or calculated from measured particle
motion data, said method comprising:
(a) using a computer to simulate the measured data (“simulated data”) with a forward model that includes a water propagation
operator between source locations and receiver locations and a term representing primary impulse responses;

(b) updating the primary impulse responses by iterative optimization to minimize a difference between the measured data and
the simulated data; and

(c) using the updated primary impulse responses to correct the measured data for multiple reflections, or for further processing
to interpret for indications of hydrocarbon potential.

1. A marine vessel comprising:
a hull having a height defining a first length;
a plurality of land propulsion mechanisms positioned adjacent to the hull;
a plurality of water propulsion devices connected to the hull;
an ice cutter operatively connected to the vessel, the ice cutter having an ice cutter length greater than the first length
to cut an opening in an ice floe sufficient for a riser to slide through as the ice floe passes under the hull; and

a control system operatively connected to the plurality of land propulsion mechanisms, the ice cutter and the plurality of
water propulsion devices, the control system is constructed and arranged to control the position of the vessel with respect
to a wellhead by operation of the plurality of land propulsion mechanisms or the plurality of water propulsion devices or
a combination thereof.

41. A method of heating a subsurface formation using electrical resistance heating, comprising:
forming a first wellbore that penetrates an interval of organic-rich rock within the subsurface formation;
forming at least one fracture in the surface formation from the first wellbore and within the interval of organic-rich rock;
placing a first electrically conductive proppant into the at least one fracture, the first electrically conductive proppant
having a first bulk resistivity;

forming a plurality of second wellbores;
placing a second electrically conductive proppant at least partially into the at least one fracture from each of the second
wellbores, thereby forming a plurality of terminals, the second electrically conductive proppant being in electrical communication
with the first electrically conductive proppant, and wherein the second electrically conductive proppant has a second bulk
resistivity that is lower than the first bulk resistivity;

passing electric current through the second electrically conductive proppant at a first terminal, and through the first electrically
conductive proppant, such that heat is generated within the at least one fracture by electrical resistivity; and

switching from the first terminal to a second terminal such that electric current is passed through the second electrically
conductive proppant at the selected terminal, and through the first electrically conductive proppant to generate heat within
the at least one fracture.

1. A multiphase separation system, comprising:
an inlet line configured to allow a multiphase fluid to flow into the multiphase separation system, the inlet line comprising
a plurality of divisions configured to lower a velocity of the multiphase fluid and feed the multiphase fluid into a distribution
header;

the distribution header configured to split the multiphase fluid among a plurality of pipes, wherein each of the plurality
of pipes includes an expansion zone forming part of each of the plurality of pipes and disposed upstream of a corresponding
downcomer, wherein the plurality of pipes are in the same plane as the distribution header, and wherein the expansion zone
is configured to lower a pressure within the plurality of pipes to allow entrained liquids to drain from a plurality of upper
pipes via the corresponding downcomer;

wherein each expansion zone is upstream of an upper and a lower finger and is configured to lower the pressure of the multiphase
fluid prior to separating the multiphase fluid among the upper and the lower finger;

each upper finger feeds into one of the corresponding upper pipes, which are disposed above a plane of the distribution header;
each lower finger feeds into a corresponding lower pipe;
each upper pipe is coupled to a corresponding lower pipe by the corresponding downcomer; and
each upper pipe is configured to allow entrained liquids to drain to the corresponding lower pipe via the corresponding downcomer.

1. A computer-implemented method for segmenting a 2-D or 3-D volume of geophysical data representing a subsurface region for
interpretation of physical structure in the subsurface region, said method comprising:
identifying curves or surfaces in the geophysical data,
using a computer to match up pairs of the curves or surfaces according to a selected measure of shape similarity,
using the matched-up curves or surfaces to define geobodies or faults in the geophysical data volume,
interpreting the geobodies or faults to indicate physical structure of the subsurface region, and
using the interpreted physical structure to explore for or produce hydrocarbons.

1. A computer-implemented method for accelerating convergence of iterative inversion of seismic data to obtain a model of
one or more physical parameters in a subsurface region, comprising:
using local cost function optimization, wherein an assumed or current model is updated to reduce misfit between the seismic
data and model-simulated data, wherein a frequency spectrum of the updated model is controlled in a first iteration and thereafter
to match a known or estimated frequency spectrum for the subsurface region;

wherein the controlling of the frequency spectrum comprises applying a spectral-shaping filter to a gradient of a cost function
in model parameter space used to determine the update to the assumed or current model, said spectral-shaping filter being
derived according to a criterion that the spectrum of the gradient of the cost function should match the known or estimated
frequency spectrum for the subsurface region.

1. A method of enhancing a geologic model of a subsurface region, comprising:
(a) obtaining a bed topography of the subsurface region, the bed topography defined by a plurality of cells, each of the cells
having an elevation associated with its cell center;

(b) representing the bed topography as a cell-centered piecewise constant representation based on the elevations associated
with the plurality of cells;

(c) reconstructing the bed topography to produce a spatially continuous surface;
(d) calculating flux and gravitational force-related source terms based on the reconstructed bed topography by a computer;
(e) calculating fluxes between at least two of the cells, taking into account variations of the bed topography across a face
between the at least two of the cells, wherein calculating fluxes between at least two of the cells is performed according
to the following equation:


wherein represents a flux per unit width between two cells at the location that is a distance l from a cell face middle line between
the at least two of the cells, represents a unit vector perpendicular to a boundary between the at least two of the cells on an unstructured grid, l0 represents half of the length of the boundary between the at least two of the cells, represents a first expansion coefficient corresponding to a zeroth order flux per unit width at the center of the edge between
the at least two of the cells, represents a second expansion coefficient, represents the square of a dimensionless maximum fluid depth change in a first of the at least two of the cells, represents a third expansion coefficient, represents the square of a dimensionless maximum fluid depth change in a second of the at least two of the cells, represents a fourth expansion coefficient, represents a dimensionless maximum fluid depth change in the first of the at least two of the cells, and represents a dimensionless maximum fluid depth change in the second of the at least two of the cells;

(f) predicting at least one of fluid flow, deposition of sediments onto the bed, and erosion of sediments from the bed using
the fluxes and gravitational force-related source terms;

(g) inputting the predicted at least one of fluid flow, deposition and erosion into the geologic model of the subsurface region;
(h) using the geologic model to predict characteristics of the subsurface region;
(i) outputting the predicted characteristics of the subsurface region; and
(j) extracting hydrocarbons from the subsurface region based on the predicted characteristics of the subsurface region.

1. A method of operating a well configured to provide a hydraulic connection between a surface region and a subterranean,
the well including a casing string contained within a wellbore that extends between the surface region and the subterranean
formation, wherein the casing string constitutes a plurality of hydraulic pathways between the surface region and the subterranean
formation, the method comprising:
providing the casing string within the wellbore between the surface region and a first portion of the subterranean formation;
providing another tubular conduit within the wellbore between the surface region and a second portion of the subterranean
formation, the second portion of the subterranean formation extending within a portion of the subterranean formation not including
the casing string;

performing a first downhole operation in the first portion of the subterranean formation, including establishing a first fluid
communication between the surface region and the first portion of the subterranean formation using a first hydraulic pathway
of the casing string; and

performing a second downhole operation in the second portion of the subterranean formation using the another tubular conduit,
including establishing a second fluid communication between the surface region and a second portion of the subterranean formation
using a second hydraulic pathway of the casing string, wherein the second hydraulic pathway is different from the first hydraulic
pathway, the second downhole operation related to drilling the well.

1. A method for inferring presence of hydrocarbons from a seismic data volume representing a subsurface region, using local
statistical distributions of seismic data values, comprising:
(a) using two moving windows of user-selected size and shape, one being a pattern window and the other a sampling window larger
than the pattern window, wherein the sampling window moves to different locations in the seismic data volume to sample the
seismic data volume, and at each location of the sampling window the pattern window moves about within the sampling window;

(b) for each sampling window location, computing a statistical distribution of seismic data values for all pattern windows
contained within the sampling window;

(c) from the statistical distribution within a sampling window, computing an outlier probability or residue for each sampling
window; and

(d) generating, with a computer, a subsurface image that identifies geologic features, including hydrocarbon accumulations,
within the seismic data volume using the outlier probabilities or residues for the sampling windows.

1. A method for quantitatively assessing connectivity between two wells in a subsurface region for the purpose of planning
or managing production of hydrocarbons from the subsurface region, comprising:
obtaining for each of at least two wells a time series of measurements characterizing a physical or operating condition of
the well as a function of discrete time from a downhole monitoring gauge disposed within the well;

resampling each of the time series of measurements at a different time interval;
comparing, in a computer system, spectral content of a first time series of measurements from a first well of at least two
wells to spectral content of a second time series of measurements from a second well of at least two wells, wherein said comparison
between wells of spectral content of time series of measurements comprises:

(a) obtaining for each of the wells the time series of measurements characterizing the physical or operating condition of
the well, said physical or operating condition being selected to show coherence between the two wells only if the wells are
hydraulically connected through the subsurface region;

(b) estimating either cross-spectral coherence or both cross-spectral coherence and phase of the two time series, wherein
coherence or phase is estimated by a mathematical computation of cross-spectral coherence or phase, yielding numerical values
of coherence or phase at varying frequencies; and

(c) quantitatively assessing connectivity between the two wells using the estimated coherence or the estimated coherence and
phase; and

based on the comparison, determining connectivity between the at least two wells; and
based on the connectivity determination, managing production of hydrocarbons from the subsurface region using the well connectivity
assessment.

1. A method of forming a propped fracture outwardly from a wellbore in a subsurface formation, the method comprising:
(a) injecting a first fluid having a first proppant concentration into the subsurface formation to form a fracture having
a first opening width, wherein the first proppant concentration may be zero, and wherein the subsurface formation is ductile
and has at least one of a Poisson's ratio greater than or equal to 0.25 and a Young's Modulus not greater than 3.5×106 psi (2.4×104 MPa);

(b) reducing pressure in the fracture so as to allow the fracture to substantially close;
(c) injecting a second fluid having a second proppant concentration into the fracture to re-open the fracture, wherein the
second proppant concentration is greater than the first proppant concentration and wherein the re-opened fracture has a second
opening width which is less than the first opening width; and

(d) reducing the pressure in the fracture after injecting the second fluid into the fracture, wherein a portion of proppant
from the second fluid remains in the fracture to prop the fracture.

7. A mooring apparatus comprising:
one or more mooring hooks for connecting one or more mooring lines,
a mooring base;
an actuator operatively connected to each of the one or more mooring hooks and the associated mooring base, wherein the actuator
provides translational movement of the mooring hook towards the mooring base;

a vessel motion detection system for determining vessel motion data, the vessel motion data comprising one or more of vessel
direction, speed and acceleration; and

a mooring apparatus control system operatively connected to each actuator and operatively connected to the vessel motion detection
system to control translational movement of the one or more mooring hooks in response to input from the vessel motion detection
system, wherein mooring hooks connected to mooring lines which oppose the direction of the motion of the vessel are retracted
by the mooring apparatus control system to oppose detected motion of the vessel.

20. A method for forming carbon nanotubes, comprising:
forming carbon nanotubes on a catalyst in a reactor in a Bosch-reaction, wherein the catalyst prior to receipt by the reactor
comprises a roughened metal surface created by forming droplets of a molten metal and quenching the droplets in a liquid,
or by partially oxidizing a metal surface followed by reduction of the metal surface, or by creating an alloy of a catalytic
metal with aluminum and etching the alloy followed by cryogenic fracturing of the etched alloy, or by shot peening of the
catalyst against a surface to fragment the catalyst, or by any combinations thereof;

separating the carbon nanotubes from a reactor effluent to form a waste stream;
heating, via a heat exchanger, a feed gas with waste heat from the waste stream;
chilling the waste stream in an ambient temperature heat exchanger to condense water vapor, forming a dry waste gas stream;
compressing, via a compressor, the dry waste gas stream;
condensing water vapor in the dry waste gas stream in a second ambient temperature heat exchanger downstream of the compressor;
processing in a fractionation system the dry waste gas stream discharged from the second ambient temperature heat exchanger;
and

recycling a portion of the dry waste gas stream from the fractionation system to the reactor.

1. A process for managing hydrates and hydrocarbon-based solids in a hydrocarbon stream, the process comprising:
(a) introducing the hydrocarbon stream into an inlet of a system comprising at least a first cold flow reactor and a second
cold flow reactor, each cold flow reactor comprising a heat exchanger and at least one static mixer;

(b) directing at least a portion of the hydrocarbon stream to the first cold flow reactor;
(c) cooling the portion of the hydrocarbon stream directed to the first cold flow reactor to a temperature less than the hydrate
formation temperature to form a hydrate and hydrocarbon-based solids managed hydrocarbon slurry stream;

(d) directing a lesser portion of the hydrocarbon stream to the second cold flow reactor;
(e) remediating the second cold flow reactor by removing hydrate or hydrocarbon-based solids formed on internal surfaces of
the second cold flow reactor;

(f) forming a remediation slipstream comprising removed hydrate or hydrocarbon-based solids from the second cold flow reactor;
and

(g) returning the remediation slipstream from the second cold flow reactor to the inlet of the system.

1. A system comprising:
a turbine combustor comprising:
a combustor liner disposed about a combustion chamber;
a head end upstream of the combustion chamber relative to a downstream direction of a flow of combustion gases through the
combustion chamber, wherein the head end is configured to direct an oxidant flow and a first fuel flow toward the combustion
chamber;

a flow sleeve disposed at an offset about the combustor liner to define a passage, wherein the passage is configured to direct
a gas flow toward the head end and to direct a portion of the oxidant flow toward a turbine end of the turbine combustor,
wherein the gas flow comprises a substantially inert gas;

a barrier section within the passage, wherein the barrier section is configured to substantially block the portion of the
oxidant flow toward the turbine end and to substantially block the gas flow toward the head end within the passage, wherein
the barrier section is configured to provide a dynamic barrier configured to separate the passage into an oxidant section
and a cooling section, wherein the dynamic barrier comprises a fluid interface between the portion of the oxidant flow and
the gas flow where the oxidant flow and the gas flow interact, and a position of the dynamic barrier is movable along a length
of the passage; and

a controller configured to control the portion of the oxidant flow into the oxidant section and the gas flow into the cooling
section, wherein the controller is configured to move the dynamic barrier along the length of the passage based at least in
part on controlling the portion of the oxidant flow, the gas flow, or any combination thereof.

1. A method of optimizing matrix and vector operations in instruction limited algorithms that perform EOS calculations, comprising:
dividing each matrix associated with an EOS stability equation or an EOS phase split equation into a number of tiles, wherein
the tile size is heterogeneous or homogenous;

dividing each vector associated with the EOS stability equation or the EOS phase split equation into a number of strips;
storing the tiles and strips in main memory, cache, or registers, wherein the tiles or strips are stored sequentially or interleaved
in main memory, cache, or registers; and

performing the matrix and vector operations associated with successive substitutions and Newton iterations in parallel using
the tiles and strips.

1. A method of stimulating a subterranean formation that includes a well, wherein the well includes a wellbore and a liner
that defines a liner conduit, the method comprising:
perforating, with a perforation device of a stimulation assembly, a first portion of the liner to create a first perforation,
wherein the stimulation assembly includes the perforation device and a resettable sealing device coupled to the perforation
device for movement with the perforation device;

isolating, with the resettable sealing device, the first portion of the liner from fluid communication with a first downhole
portion of the liner, wherein the isolating the first portion of the liner includes expanding the resettable sealing device
to a sealing configuration with fluid from the liner conduit;

introducing a stimulant fluid from the surface region and through the first perforation;
pumping fluid through a fluid conduit and into the resettable sealing device to expand the resettable sealing device to a
motive configuration and providing a motive fluid into the liner conduit to convey the stimulation assembly along the liner
conduit; and

moving the stimulation assembly within the fluid conduit to a second portion of the liner.

1. A computer-implemented method of organizing a first group of domain objects relating to hydrocarbon management, comprising:
establishing one or more user-defined logic conditions, wherein the logic conditions include a spatial requirement and include
a graphical representation of one or more polygon, polyhedra and other geometric construct;

selecting a plurality of the domain objects in the first group of domain objects, wherein the first group of domain objects
are associated with hydrocarbon management and wherein the domain objects comprise one or more of a wellbore, a well completion,
a well log, a well target, a well core, tubulars, a surface, a three dimensional model, a seismic cube, a three-dimensional
surface, a well zone, a point, a point set, a polyline, and hydrocarbon management data;

determining whether any of the selected plurality of domain objects satisfies the logic conditions;
creating a second group of domain objects that includes the logic conditions and a list of domain objects satisfying the logic
conditions; and

performing an operation command on the second group of domain objects such that the same operation command is performed on
all domain objects listed in the second group of domain objects, wherein the operation command comprises one or more of deleting,
renaming, displaying, and modifying any part of the domain objects in the second group of domain objects or information related
thereto.

1. A method for predicting and removing near-surface noise from seismic data, comprising:
acquiring the seismic data by exciting a plurality of encoded sources operating simultaneously so as to produce time-overlapping
records that are recorded at a plurality of seismic receivers;

using locations of the sources and their respective encoding information to characterize near-surface properties affecting
propagation of seismic energy along the surface from each source to each receiver;

using a computer to predict time-overlapping noise recorded by a selected receiver; and
subtracting or adaptively subtracting, with a computer, the predicted noise from the seismic data measured by the selected
receiver to yield data with reduced near-surface noise,

wherein the characterizing of near-surface properties comprises using waveform tomography using an iterative model optimization
method.

1. A method for power generation using non-aqueous solvent, comprising:
treating oil sands with a non-aqueous solvent to extract bitumen in an extraction process;
separating the non-aqueous solvent from the bitumen in a solvent recovery process;
heating all of the separated non-aqueous solvent;
expanding all of the heated non-aqueous solvent to generate power;
cooling all of the expanded non-aqueous solvent; and
recycling at least a portion of the cooled non-aqueous solvent to the extraction process.

1. A method for completing a wellbore in a subsurface formation, the method comprising:
providing a packer assembly having a first mechanically-set packer as a first zonal isolation tool, and a second zonal isolation
tool, wherein each of the first and second zonal isolation tools comprises an internal bore for receiving production fluids,
and alternate flow channels, and the first mechanically-set packer comprises:

an inner mandrel as the internal bore,
the alternate flow channels along the inner mandrel,
a movable piston housing external to the inner mandrel;
one or more flow ports providing fluid communication between the alternate flow channels and a pressure-bearing surface of
the piston housing; and

a sealing element external to the inner mandrel and in selectively movable engagement with the piston housing;
connecting the packer assembly to a sand screen, the sand screen comprising a base pipe, a surrounding filter medium, and
alternate flow channels, wherein:

the base pipe has an inner bore in fluid communication with the internal bore of the first and second zonal isolation tools,
and

the alternate flow channels of the sand screen are in fluid communication with alternate flow channels of the first and second
zonal isolation tools;

running the packer assembly and connected sand screen into the wellbore;
setting the first mechanically-set packer by communicating fluid pressure to the piston housing through the one or more flow
ports to actuate the sealing element into engagement with the surrounding subsurface formation;

injecting a gravel slurry into the wellbore; and
injecting the gravel slurry at least partially through the alternate flow channels to allow the gravel slurry to bypass the
sealing element so that the wellbore is gravel-packed within an annular region between the sand screen and the surrounding
formation below the packer assembly.

17. A method for completing a wellbore, the wellbore having a lower end defining a completion interval, and the method comprising:
connecting a communications module to a tubular joint, the communications module comprising:
at least one alternate flow channel configured to permit a gravel slurry to partially bypass the communications module during
a gravel packing procedure, and

a control line configured to reside entirely within the wellbore for conveying an actuating command signal to a downhole tool;
running the communications module and the connected tubular joint into the wellbore;
positioning the communications module and the tubular joint in the wellbore; and
injecting a gravel slurry into an annular region formed between the communications module and the surrounding wellbore, while
providing that a portion of the gravel slurry travels through the at least one alternate flow channel to allow the gravel
slurry to partially bypass the communications module and provide gravel packing below the communications module.

1. A system for generating elemental sulfur, comprising:
a gas treatment system to provide a processed feed gas comprising carbon dioxide, hydrogen sulfide, and hydrocarbons;
a distillation column comprising a rectifying section, a freeze zone section, and a stripping section, wherein the distillation
column is configured to receive the processed feed gas, freeze carbon dioxide from the processed feed gas in the freeze zone
section, and generate a natural gas stream and a liquid high-pressure acid gas stream, wherein the liquid high-pressure acid
gas stream comprises hydrogen sulfide and carbon dioxide and is at a pressure of at least 500 psig;

a reactor configured to receive a portion of the liquid high-pressure acid gas stream and to partially combust the portion
of the liquid high-pressure acid gas stream to generate a limiting reactant;

a plurality of reactors configured with a shell side and a tube side, wherein the tube side comprises a plurality of reaction
tubes, and wherein a reaction in each of the reaction tubes between a portion of the liquid high-pressure acid gas stream
from the distillation column and the limiting reactant produces a partially-reacted high-pressure acid gas containing elemental
sulfur;

a plurality of condensers configured to condense the partially-reacted high-pressure acid gas and form an overhead acid gas
stream and a liquid elemental sulfur stream; and

a plurality of separators configured to recover elemental sulfur.

1. A method for determining a discrete physical properties model of a subsurface region, referred to herein as the model or
the subsurface model, by iteratively inverting measured geophysical data acquired from the subsurface region, comprising:
approximating a Hessian matrix of an objective function, then times a vector, called Hessian times vector, using a computer,
with a single forward-wave simulated propagation and a single computation of gradient of the objective function, in a modified
subsurface model, thereby requiring only three forward-wave or reverse-wave propagations;

wherein said approximation is based on an approximate equation for a Born scattered pressure field, pd,F, where the Hessian times vector is approximated by a gradient computation using pd,F as an artificial residual;

then computing a direction in model parameter space for an update to a current model by multiplying inverse of the Hessian
matrix times a gradient of the objective function, wherein the inverse of the Hessian matrix is computed iteratively using
a conjugate gradient method in which said approximate Hessian times vector is used to evaluate the Hessian matrix times a
model perturbation vector;

performing a line search to determine magnitude of the model update using said computed direction; and
adding the model update to the current model to form an updated model, and using the updated model for geophysical prospecting.

1. A method for identifying and sampling target materials with one or more buoys, comprising:
deploying one or more buoys to a location in a body of water, wherein at least one of the one or more buoys has a buoy monitoring
section that includes a measurement component and a sampling component, wherein the sampling component comprises a sampling
assembly comprising a plurality of individual sampling containers;

obtaining measurement data associated with the body of water with a measurement component;
determining whether target material is present in the measurement data, wherein the target material comprises one or more
of biological, chemical, hydrocarbon and any combination thereof;

obtaining a sample of the target material with the sampling component when the measurement data indicates the presence of
the target material; and

storing the obtained sample in one or more of the individual sample containers.

1. A system for generating a gas suitable for producing power from a coalbed, comprising:
a hydrocarbon source;
a chemical convertor in fluid communication with the hydrocarbon source configured to convert a feedstock from the hydrocarbon
source into a gas mixture comprising CO2 and H2;

an injection well in direct fluid communication with both the chemical converter and the coalbed configured to inject the
gas mixture comprising CO2 and H2 into the coalbed;

the coalbed configured to receive the gas mixture and adsorb and sequester a portion of the CO2 in the coalbed, wherein the coalbed is separate from the hydrocarbon source;

a production well configured to harvest a production gas from the coalbed, wherein the production gas comprises H2 and CH4 and wherein the production gas comprises greater than about 10 mole H2 and greater than about 10 mole % CH4, wherein the composition of the production gas is on a dry basis; and

a pipeline directly connecting the production well to a combustion apparatus that powers an electrical generator, the pipeline
configured to deliver the harvested production gas to the combustion apparatus, wherein the pipeline does not have a recycle
means with the coalbed.

1. A method for analyzing seismic data, comprising the acts of:
accessing a set of seismic data comprising a plurality of features of interest;
processing the plurality of features of interest using a classification algorithm, wherein the classification algorithm is
a multi-class classifier based on a decision tree that outputs a list of possible classifications for each feature of interest
with an associated probability for each listed classification for a respective feature; and

processing the list of possible classifications using a ranking algorithm, wherein the ranking algorithm outputs a ranked
list of possible classifications for each feature of interest;

wherein, during operation, the ranking algorithm:
generates a pool query set of respective queries related to the features of interest, wherein each query comprises a pair
of ranked features of interest that has been classified as the same type of feature;

submits one or more queries to a reviewer to obtain reviewer feedback, wherein the reviewer feedback to each query comprises
a selection of which feature in the pair of ranked features is more likely correctly classified; and

updates the operation of the ranking algorithm based on the reviewer feedback to the queries.

1. A method of providing a plug-in installer framework, comprising:
creating an installer plug-in conforming to a host application's defined Application Programming Interface (API);
reading configuration information with the installer plug-in;
contacting an application server with the installer plug-in to determine which plug-in files to update in local storage;
downloading updated plug-in files from an application server to local storage;
updating the plug-in files which are used to create additional plug-ins;
loading each of the additional plug-ins in an internal collection of the installer plug-in;
maintaining the internal collection of the additional plug-ins in an additional plug-in library of the installer plug-in,
wherein the host application is unaware of the additional plug-in library; and

loading the additional plug-ins through the installer plug-in when a functionality of at least one of the additional plug-ins
is called, wherein the host application is unaware of the additional plug-ins.

1. A method of solvent surveillance, comprising the steps of: (a) measuring an amount of a native bitumen marker (NBM) in
heavy oil; (b) measuring an amount of the NBM in a recovery-aid solvent; (c) measuring an amount of the NBM in a blend, wherein
the blend comprises the heavy oil and the recovery-aid solvent; (d) applying a blending model to determine a fraction of the
recovery-aid solvent in the blend, wherein the blending model is at least partially described by formula: the fraction of
the recovery-aid solvent in the blend=(NBMo-NBMb)/(NBMo-NBMras); wherein NBMo is the amount of the NBM in the heavy oil, NBMb
is the amount of the NBM in the blend, NBMras is the amount of the NBM in the recovery-aid solvent; (e) generating an output
that corresponds to the amount of recovery-aid solvent in the blend; and (f) adjusting at least one step in a solvent recovery
process in response to the output.

1. A method of inhibiting scale formation in a hydrocarbon well that extends within a subterranean formation, the method comprising:
locating a selective-release scale inhibitor within a portion of the subterranean formation, wherein the selective-release
scale inhibitor is configured to be at least substantially insoluble in hydrocarbons;

producing a reservoir fluid from the subterranean formation via the hydrocarbon well; and
facilitating a change in environmental conditions present within the portion of the subterranean formation from initial environmental
conditions, in which the selective-release scale inhibitor is at least substantially insoluble in water, to subsequent environmental
conditions, in which the selective-release scale inhibitor is soluble in water, wherein the facilitating includes initiating
dissolution of the selective-release scale inhibitor responsive to fluid contact between the selective-release scale inhibitor
and water at the subsequent environmental conditions;

wherein the selective-release scale inhibitor is a first selective-release scale inhibitor, and further wherein the method
includes locating a second selective-release scale inhibitor within the portion of the subterranean formation, wherein dissolution
of the second selective-release scale inhibitor in water suppresses dissolution of the first selective-release scale inhibitor
within water.

1. A method of injecting a fluid into a subsurface formation, the subsurface formation having at least two subsurface intervals,
and the method comprising:
running a string of injection tubing into a wellbore, the wellbore being lined with a string of casing that substantially
traverses each of the at least two subsurface intervals, with the casing being perforated along each of the at least two intervals
and an annulus being formed between the tubing and the surrounding perforated casing;

setting a bypass packer along the string of tubing intermediate the at least two subsurface intervals, the bypass packer having
a defined flow-through area that is sized to impart a defined incremental pressure drop so as to optimize fluid injection
into the at least two subsurface intervals;

setting a sealing packer within the annulus above or proximate a top of an upper-most of the at least two subsurface intervals
to seal the annulus; and

injecting fluids down the string of injection tubing, back up the annulus, through the channels in the bypass packer, and
into each of the at least two subsurface intervals.

1. A method of performing a simulation of a subsurface hydrocarbon reservoir, the reservoir being approximated by a reservoir
model having a plurality of cells, each cell having associated therewith an equation set representing a reservoir property,
the method comprising:
(a) providing an initial guess to a solution for a system of equations formed using the equation set for each cell in the
plurality of cells, wherein providing the initial guess comprises using a Jacobian matrix;

(b) using an iterative root-finding method and the initial guess to solve for a solution to the system of equations in a computer;
(c) establishing a list of unconverged cells, the unconverged cells having equation sets that have not satisfied a convergence
criterion;

(d) when the number of unconverged cells is greater than a predetermined amount, adding, to the list of unconverged cells,
neighbor cells of the unconverged cells, each of said neighbor cells having an equation set that satisfies the convergence
criterion;

(e) repeating parts (b), (c), and (d), substituting the solved solution for the initial guess or the most recent solved solution
and substituting the equation sets corresponding to the cells in the list of unconverged cells for the system of equations
or equation sets from the most recent iteration, until substantially all equation sets satisfy the convergence criterion,
and wherein the size of the Jacobian matrix varies with each iteration;

(f) when substantially all equation sets satisfy the convergence criterion, employing a post-Newton material balance corrector
and outputting the solved solution as a simulation of the subsurface reservoir; and

(g) managing hydrocarbons based on the simulation.

1. An adsorbent bed system comprising:
a first adsorbent bed of adsorbent material capable of selectively removing a target gas from a gaseous mixture, which adsorbent
bed is substantially cylindrical shape;

a second adsorbent bed of adsorbent material capable of selectively removing a target gas from a gaseous mixture, which second
adsorbent bed has a substantially cylindrical shape and being disposed about the first bed of adsorbent material and is substantially
the same face cross-sectional area as the face cross-sectional area of the first adsorbent bed, wherein the first adsorbent
bed and second adsorbent bed are separated by a material that is non-permeable to the gas flowing through the first adsorbent
bed and the second adsorbent bed and the non-permeable material prevents leakage of gas between the first adsorbent bed and
the second adsorbent bed; and

where the beds are connected at feed and product ends via non-rotary valving or and where the non-rotary valving comprises
poppet valves, at least some of which share a common actuator.

10. A downhole assembly configured to be conveyed within a wellbore, the downhole assembly comprising:
An energy-storing structure defining at least a charged state and a discharged state in response to a discharging force generated
by conveying the downhole assembly that exceeds a threshold discharging force established within the energy-saving structure,
and generating a motive force by transitioning form the charged stated to the discharged state;

A fluid propulsion device that is configured to receive the motive force from the energy-storing structure and to generate
a fluidizing stream therefrom; and

A fluidizing assembly that is configured to emit the generated fluidizing stream from the downhole assembly along the conveyed
horizontal portion of the wellbore and provide the fluidizing stream to a cuttings bed to fluidize a portion of the cuttings
bed in immediate proximity to the downhole assembly.

1. A method for semi-airborne electromagnetic prospecting for fluids or minerals, comprising:
deploying a plurality of electromagnetic receivers on the Earth's surface over a subsurface region;
energizing an airborne electromagnetic transmitter in a vicinity above the receivers;
recording at least one component of electromagnetic field data excited by the transmitter in the receivers, wherein the electromagnetic
transmitter transmits, and the receivers record, multiple frequencies for a single offset;

analyzing the at least one component of electromagnetic field data generated from the semi-airborne electromagnetic prospecting
for subsurface resistivity; and

interpreting the resistivity for evidence of hydrocarbons.

1. A system for removing acid gases from a raw gas stream, comprising:
a dehydration vessel for receiving the raw gas stream, and separating the raw gas stream into a dehydrated raw gas stream
and a stream comprised of an aqueous fluid;

a heat exchanger for cooling the dehydrated gas stream, and releasing a cooled sour gas stream;
a cryogenic distillation tower that receives the cooled sour gas stream, and separates the cooled sour gas stream into (i)
an overhead gas stream comprised primarily of methane, and (ii) a bottom liquefied acid gas stream comprised primarily of
carbon dioxide, wherein the cryogenic distillation tower separates the cooled sour gas stream by freezing the carbon dioxide
in the cooled sour gas stream;

a final co-current contactor configured to (i) receive the bottom liquefied acid gas stream, (ii) receive a partially methane-enriched
gas stream from a previous co-current contactor, (iii) release a final methane-enriched gas stream to the cryogenic distillation
tower, and (iv) release a first partially-stripped acid gas liquid to the previous co-current contactor; and

a first co-current contactor configured to (i) receive a stripping gas, (ii) receive a second partially-stripped acid gas
liquid from a second co-current contactor, (iii) release a final stripped acid gas liquid, and (iv) release a first partially-methane-enriched
gas stream to the second co-current contactor; and

wherein the co-current contactors are arranged in series and wherein the stripping gas comprises carbon dioxide; and
wherein the at least one of the co-current contactors comprise a mixing device and a coalescing device.

1. A natural gas liquefaction facility, comprising:
an electrical power source;
a primary refrigeration unit for chilling natural gas to a temperature of liquefaction;
a first refrigerant inlet line for delivering a first refrigerant to the primary refrigeration unit;
a natural gas inlet line for delivering natural gas to the primary refrigeration unit;
a natural gas outlet line for releasing a liquefied natural gas from the primary refrigeration unit;
at least one superconducting electrical component which incorporates a superconducting material so as to improve electrical
efficiency of the component by at least one percent over what would be experienced through the use of non-superconducting
electrical components;

an incoming refrigerant line for delivering a refrigerant to the at least one superconducting electrical component for maintaining
the at least one superconducting electrical component below a critical temperature;

an outgoing refrigerant line for releasing the refrigerant from the at least one superconducting electrical component;
an ancillary refrigeration unit;
an incoming refrigerant slip line, the incoming refrigerant slip line taking a portion of the first refrigerant from the incoming
refrigerant inlet line and delivering the portion of the first refrigerant to the ancillary refrigeration unit as a third
refrigerant; and

an outgoing refrigerant slip line for delivering a portion of the third refrigerant to the incoming refrigerant line used
for delivering a second refrigerant to the at least one superconducting electrical component.

1. A method for displaying selected portions of a three-dimensional (3D) volumetric data set representing a subsurface formation,
comprising:
generating at least one two-dimensional (2D) canvas, the 2D canvas corresponding to a plane in the 3D data set, the 2D canvas
being shown in a first display window;

creating one or more 2D primitives on the 2D canvas;
creating a 3D volume from the one or more 2D primitives created on the 2D canvas;
forming a volumetric region, which is a subset of the 3D volumetric data set, from an intersection between the 3D volume created
from the one or more 2D primitives and the 3D volumetric data set; and

displaying the volumetric region in a 3D scene, the 3D scene being shown in a second display window.

1. A method for completing a well in a reservoir, comprising:
injecting a stimulation fluid to stimulate a first interval in the reservoir, wherein the stimulation fluid is at a pressure
sufficient to open a plurality of check valves in the first interval, allowing stimulation fluid to flow into the first interval,
and wherein the stimulation fluid from at least one check valve flows into the first interval through a plurality of openings
in a distribution chamber;

dropping a plurality of ball sealers into the well to stop a flow of the stimulation fluid into the first interval and begin
treatment of a second interval, wherein the ball sealers are configured to block flow through the plurality of check valves
in the first interval, wherein the stimulation fluid from at least one check valve flows into the second interval through
a plurality of openings in a distribution chamber;

injecting the stimulation fluid to stimulate a subsequent interval in the reservoir, wherein the stimulation fluid is at a
pressure sufficient to open a plurality of check valves in the subsequent interval, allowing stimulation fluid to flow into
the subsequent interval, and wherein the stimulation fluid from at least one check valve flows into the subsequent interval
through a plurality of openings in a distribution chamber; and

repeating the dropping of ball sealers until all intervals are treated.

1. A system for transporting a hydrocarbon from a production center, comprising:
a water line to a production center;
an injection manifold at the production center configured to inject an aqueous stream from the water line into a production
stream, wherein the production stream comprises a hydrocarbon, and wherein the injection of the aqueous stream forms a transportation
stream having a water external phase;

a transportation line from the production center, wherein the transportation line comprises a plurality of static mixers,
and wherein the transportation line is configured to carry the transportation stream to a surface facility;

a separation unit at the production center, wherein the separation unit is configured to separate a gas stream from the transportation
stream; and

the surface facility, wherein the surface facility comprises:
a separation system configured to separate the hydrocarbon from an aqueous phase;
a treatment system configured to form the aqueous stream from the aqueous phase; and
a pump system configured to return the aqueous stream to the production center through the water line.

1. A method for detecting at least one chemical species using a detection system including multiple electromagnetic radiation
detectors, the method comprising:
obtaining a first image from a first electromagnetic radiation detector configured to detect emission or absorption of the
at least one chemical species released into an environment, the image including a first plurality of pixels, each pixel having
an associated intensity value;

obtaining a second image from a second electromagnetic radiation detector configured to provide a reference background, the
image including a second plurality of pixels, each pixel having an associated intensity value;

adjusting one or more intensity values of the first plurality of pixels based on one or more intensity value parameters of
the first image;

adjusting one or more intensity values of the second plurality of pixels based on the one or more intensity value parameters
of the first image;

obtaining subsequent images from the first electromagnetic radiation detector and the second electromagnetic radiation detector;
adjusting pixels of the subsequent images from the first electromagnetic radiation detector based on the adjusted intensity
values of the first plurality of pixels;

adjusting pixels of the subsequent images from the second electromagnetic radiation detector based on the adjusted intensity
values of the second plurality of pixels; and

determining the presence or absence of a chemical species based, at least in part, on a comparison of the adjusted images
from the first electromagnetic radiation detector and the second electromagnetic radiation detector, wherein the first plurality
of pixels of the first image and the second plurality of pixels of the second image are substantially temporally and spatially
aligned.

1. A method of performing a parallel reservoir simulation, comprising:
generating a distributed data representation in a computer storage system, wherein the data representation comprises at least
one interconnection weight that represents the magnitude of an interconnection between each of a plurality of computational
cells in a computational mesh, and wherein the data representation comprises a Jacobian matrix;

on a first processor, determining a first threshold value, wherein determining the first threshold value comprises:
calculating a maximum interconnection weight for interconnections of each of a first portion of the plurality of computational
cells to all adjoining computational cells;

identifying the largest value of the maximum interconnection weight for all of the first portion of the plurality of computational
cells;

identifying the smallest value of the maximum interconnection weights for all of the first portion of the plurality of computational
cells; and

selecting the first threshold value to lie between the largest value and the smallest value,
on a second processor, determining a second threshold value, wherein determining the second threshold value comprises:
calculating a maximum interconnection weight for interconnections of each of a second portion of the plurality of computational
cells to all adjoining computational cells;

identifying the largest value of the maximum interconnection weight for all of the second portion of the plurality of computational
cells;

identifying the smallest value of the maximum interconnection weights for all of the second portion of the plurality of computational
cells; and

selecting the second threshold value to lie between the largest value and the smallest value,
selecting a final threshold value based at least in part on the first threshold value and the second threshold value;
comparing the final threshold value to each interconnection weight wherein comparing the final threshold value to each interconnection
weight comprises using the formula

wherein dij and dji represent the diagonal elements of the computational cells i and j in the Jacobian matrix, wherein ? represents the final
threshold value, and wherein aij represents transmissibility, and wherein comparing the final threshold value to each interconnection weight does not involve
global communications for this iteration or any subsequent iteration; and
setting any interconnection weight that is equal to or less than the final threshold value to zero.

1. A method for modeling a hydrocarbon reservoir, comprising:
deriving a computational mesh from a fine unstructured mesh using a multilevel mixed multiscale finite volume (MMMFV) method,
comprising:

constructing an interaction region;
generating a primary mesh;
computing a first algebraic multilevel basis function for a pressure, wherein the first algebraic multilevel basis function
is based at least in part on a discrete harmonic function;

computing a second algebraic multiscale basis function for a velocity approximation, wherein the second algebraic multiscale
basis function is solved to satisfy the following:


wherein K14 represents an interaction sub region with boundaries e1, e4, l11, and l12, and wherein the basis functions v1 and v2 are constants when the coefficients are the same in each fine cell in the sub region K14; and

simulating the hydrocarbon reservoir using the computational mesh; and
generating a data representation of a physical hydrocarbon reservoir in a non-transitory, computer-readable medium based at
least in part on the results of the simulation.

1. A method for exploration, production, and development of hydrocarbons comprising:
obtaining a sample comprising hydrocarbons associated with a subsurface source interval;
analyzing the sample for a geochemical signature, wherein the geochemical signature comprises one or more of a multiply substituted
isotopologue signature and a position specific isotope signature for a one or more specific hydrocarbon compound;

determining one or more historical temperatures based on the one or more of multiply substituted isotopologue signature and
position specific isotope signature;

defining generation timing based on the determined one or more historical temperatures; and
developing or refining an exploration, development or production strategy based on the defined generation timing.

1. A method for remediating a slurry pond, comprising:
distributing one or more wicks into the slurry pond wherein the one or more wicks buoyantly float in a slurry at least partially
below a level of a supernatant; and

using a mechanism to control a flotation of the one or more wicks so that one end of the one or more wicks floats near an
interface between a layer of the slurry and the level of supernatant, wherein the mechanism comprises a diaphragm, weights,
weighted buoys, floats, or a selection of a density of the material of the one or more wicks, or any combinations thereof;
and

wherein one end of the one or more wicks floats slightly above an interface between the layer of the slurry and the level
of supernatant.

1. A method, comprising:
performing dual-side depressurization on a hydrate blockage in a subsea flow line, wherein dual-side depressurization includes,
reducing pressure on a topside of the hydrate blockage in the subsea flow line by removing liquid from within a subsea riser
with a tube bundle having a plurality of capillary tubes, the tube bundle having a first end in fluid communication with the
liquid within the subsea riser, wherein the subsea riser is in fluid communication with the subsea flow line, and wherein
the liquid is removed from the subsea riser through the plurality of capillary tubes from the first end to a second end of
the tube bundle,

reducing pressure on a backside of the hydrate blockage, and
concurrently controlling the reduction in pressure on the topside of the hydrate blockage and the backside of the hydrate
blockage.

7. A method for removing entrained liquid hydrocarbons in a countercurrent contact separator to produce a lean hydrocarbons
gas, comprising:
introducing a gas stream into an inlet of the countercurrent contact separator;
flowing the gas stream through a bulk separator to capture a portion of the entrained liquid hydrocarbons;
flowing the gas stream through a plurality of cyclone bundles, wherein the plurality of cyclone bundles are located in risers
to capture a remaining fraction of the entrained liquid hydrocarbons;

flowing the captured entrained liquids downward into a drain line countercurrent to the gas stream;
introducing a contact liquid into an inlet of the column;
removing the captured entrained liquids through a bottom outlet of the countercurrent contact separator; and
removing the lean hydrocarbons gas through a top outlet of the countercurrent contact separator.

1. A paraffinic froth treatment process wherein a fine tailings stream obtained from a water extraction process practiced
on oil sands is added during the process, wherein the fine tailings stream excludes tailing solvent recovery unit (TSRU) tailings.

1. A method for producing hydrocarbons from and storing CO2 in an organic-rich rock formation, the method comprising the steps of:
injecting the CO2 into an injection well in the organic-rich rock formation and producing the hydrocarbons, wherein the hydrocarbons substantially
include natural gas, from a production well when a drainage volume of the production well has an average reservoir pressure
equal to or less than a predetermined pressure, wherein the injection well is in fluid communication with the production well;
and

capping the production well and feeding the CO2 into the injection well when the produced hydrocarbons include a CO2 mole fraction greater than or equal to a predetermined mole fraction.

1. A bidirectional flow control device for attachment to a tubular member, the tubular member defining an internal flow passage,
comprising:
(a) a nozzle insert comprising a first end and a second end, the nozzle insert axially positionable within a bore, the bore
in fluid communication with the internal flow passage of the tubular member and comprising a first sealable surface, the nozzle
insert comprising a nozzle passage in fluid communication with the bore, and a second sealable surface for mating with the
first sealable surface, and a first biasing member seat;

(b) a cover plate positioned adjacent the first end of the nozzle insert, the cover plate comprising a production orifice
in fluid communication with the nozzle passage of the nozzle insert and a plurality of stimulation orifices, the plurality
of stimulation orifices in fluid communication with a plurality of stimulation passages, the stimulation passages in fluid
communication with the bore, the cover plate further comprising a second biasing member seat; and

(c) a biasing member, the biasing member positioned between the first biasing member seat and the second biasing member seat,
the biasing member structured and arranged to exert a biasing force sufficient to place first sealable surface and the second
sealable surface in sealing engagement when the internal tubular pressure is below a set-point value.

1. A method for enhanced recovery of coalbed methane, comprising:
compressing a gaseous fuel for use in a semi-closed Brayton cycle power plant;
generating a gas mixture comprising N2 and CO2 in the semi-closed Brayton cycle power plant operating to combust the gaseous fuel and an oxygen component of an oxidant at
a stoichiometric ratio;

injecting at least a portion of the gas mixture into a coal bed; and
recovering a mixed production gas comprising methane from the coal bed.

1. A method for planning a well path, comprising:
defining a proxy constraint volume as a three-dimensional (3D) cellular volume having one or more cells, where each cell has
at least one value derived from data from a 3D earth model;

defining an initial well path within user defined drilling parameter constraints;
defining acceptable constraint parameters to be applied to values derived from an intersection of the initial well path and
the proxy constraint volume;

if the intersection of the initial well path and the proxy constraint volume is within the acceptable constraint parameters,
indicating the initial well path is within the acceptable constraint parameters; and

if the intersection of the initial well path and the proxy constraint volume is not within the acceptable constraint parameters,
iteratively adjusting the initial well path to create successive well paths until at least one of the successive well paths
is within the acceptable constraint parameters for the values derived from the intersection of the well path and proxy constraint
volume.

1. A sand control device for restricting the flow of particles within a wellbore, the sand control device comprising:
at least a first compartment, wherein each compartment comprises:
a base pipe having a permeable section and an impermeable section,
a first filtering conduit circumscribing the base pipe and forming a first annular region between the base pipe and the first
filtering conduit, the first filtering conduit having a filtering medium adjacent the impermeable section of the base pipe,

a second filtering conduit also circumscribing the base pipe and forming a second annular region between the base pipe and
the second filtering conduit, the second filtering conduit having a filtering medium adjacent the permeable section of the
base pipe, wherein the filtering medium of the first filtering conduit and the filtering medium of the second filtering conduit
each comprises a wound wire screen or a wire mesh,

a blank tubular housing circumscribing the second filtering conduit and forming a third annular region between the second
filtering conduit and the surrounding housing, and

an under-flow ring disposed along the base pipe between the first filtering conduit and the second filtering conduit, the
under-flow ring placing the first annular region in fluid communication with the third annular region, and the under-flow
ring having an outer diameter that sealingly receives the blank tubular housing at an end.

1. A process for upgrading a bitumen production stream, the process comprising:
providing a bitumen production stream;
adding clay and/or adding or removing water, where required, to achieve a water content of 10 to 40 wt % and a clay content
of 5 to 15 wt % to produce a feed stream; and

heating the feed stream to near-critical or super-critical conditions of the water to produce an upgraded bitumen stream and
solids; wherein the difference in the specific gravity between the upgraded bitumen stream and the water is greater than the
difference in the specific gravity between the bitumen production stream and the water, and the viscosity of the upgraded
bitumen stream is lower than the viscosity of the bitumen production stream; and

separating the water and solids from the bitumen production stream.

1. A method for managing an oil release with one or more airborne devices, comprising:
deploying a marine vessel having an airborne detection device to a location in a body of water near an oil slick;
hovering the airborne detection device above the oil slick;
measuring thickness of the oil slick at the location by contacting the oil slick with a measurement component deployed from
the airborne detection device; and

transmitting a signal associated with the thickness of the oil slick to a command unit, wherein the measurement component
includes an imaging camera to contact the oil slick, and measuring the thickness further includes capturing an image of an
air-oil interface and an oil-water interface, and retracting the imaging camera out of the oil slick.

1. A computer-implemented method for processing seismic data from a subsurface region to obtain indication of hydrocarbon
potential of the subsurface region, comprising:
estimating velocity dispersion of seismic surface waves in the subsurface region by a method comprising transforming the seismic
data to frequency-slowness domain resulting in a beam-formed field, and then modeling the beam-formed field with an analytic
dispersion beam and fitting the beam-formed field with the analytic dispersion beam by performing nonlinear constrained optimization;

using the estimated seismic velocity dispersion in processing the seismic data or in determining local earth properties in
the subsurface region; and

using the processed seismic data or the local earth properties for determining presence, quality or other characteristic of
hydrocarbon reservoirs;

wherein at least the nonlinear constrained optimization is performed using a computer, and
wherein the estimated seismic velocity dispersion is determined at locations throughout the subsurface region and is compiled,
by a computer, into a 3-D dispersion volume, which is used for further processing of the seismic data to remove unwanted surface-wave
noise or to characterize near-earth-surface properties.

1. A method for modeling properties of a reservoir, comprising:
constructing a coarse computational mesh for the reservoir in a computer system, wherein the coarse computational mesh comprises
a plurality of cells;

determining a plurality of flows for each of the plurality of cells based on Dirichlet boundary conditions, wherein determining
the plurality of flows for each of the plurality of cells comprises:

selecting a plurality of pressure points along a plurality of boundaries of the cell, wherein selecting the plurality of pressure
points at the boundary comprises:

selecting a mid-point of a boundary of the cell if a scalar permeability or all entries of a permeability tensor at the boundary
is less than a first pre-determined threshold;

selecting two points close to two ends of the boundary if a maximum permeability or a maximum entry of the permeability tensor
at the boundary is greater than the first pre-determined threshold;

selecting a first pressure point if the maximum of the scalar permeability or entries of the permeability tensor is greater
than the first pre-determined threshold;

selecting the first pressure point where the scalar permeability or an entry of the permeability tensor reaches the maximum;
and

selecting additional pressure points away from the first pressure point, wherein a spacing, h, of the additional pressure
points, comprises:


where km is equal to the maximum entry of the permeability tensor, and a, b, c, and d are constant parameters;

associating the plurality of pressure points with a corresponding plurality of segments;
determining a plurality of solutions to a steady-state pressure equation for the cell based on the plurality of pressure points
at the boundary and a first Dirichlet boundary condition;

computing a first flow rate across each of the plurality of segments based on a steady-state pressure equation solution;
determining a solution to an inhomogenous pressure equation for the cell based on a second Dirichlet boundary condition; and
computing a second flow rate across each of the plurality of segments based on the solution to the inhomogenous pressure equation,
wherein the plurality of flows comprise the second flow rate; and

determining a solution to a coarse pressure equation for the reservoir based on the plurality of flows.

1. A method for evaluating cement integrity in a cased well drilled into a subsurface formation with a cement sheath installed
in an annular region between the well casing and the formation, comprising:
obtaining an open hole neutron log and hole dimensions acquired from the well before casing and cementing, and obtaining a
cased hole neutron log and related information including one or more of casing size and weight, cement weight, and mud weight,
acquired from the well after casing and cementing;

with the open and cased hole neutron logs, hole dimensions, and the related information as input quantities, using a mathematical
model, operated on a computer, to determine a volume of fluid filled channels in the cement sheath; and

estimating the cement integrity based on the fluid filled channel volume.

1. A method of creating a check plug of known permeability comprising:
creating a cylinder with a diameter D with an impermeable matrix;
creating a channel in the cylinder by:
forming a passage in the cylinder;
attaching a glass capillary tube containing the channel within the passage; and
sealing the annulus between the passage and the glass capillary tube,
wherein the channel has a known diameter d of less than 50 microns; and
calculating the permeability through the check plug by the equation

wherein n is the number of channels.

1. A method of removing wellbore liquid from a wellbore that extends from a surface location into a subterranean formation, the method comprising:providing a downhole piezoelectric pump within the wellbore, the downhole piezoelectric pump comprising a liquid inlet valve configured to selectively introduce the wellbore liquid into a compression chamber of the downhole piezoelectric pump;
electrically powering the downhole piezoelectric pump; and
pumping the wellbore liquid from the wellbore with the downhole piezoelectric pump, wherein the pumping includes:
(i) pressurizing the wellbore liquid with the downhole piezoelectric pump to generate a pressurized wellbore liquid at a discharge pressure; and
(ii) flowing the pressurized wellbore liquid at least a threshold vertical distance to a surface region;
(iii) detecting a gas lock condition of the downhole piezoelectric pump; and
(iv) opening the liquid inlet valve responsive to detecting the gas lock condition.

1. A computer-implemented method for inversion of measured geophysical data to determine a physical properties model for a
subsurface region, comprising:
(a) obtaining the measured geophysical data from a geophysical survey of the subsurface region;
(b) inverting the measured geophysical data by iterative inversion process, using a computer, to determine an updated physical
properties model for the subsurface region from an initial physical properties model, wherein:

(i) at least one iteration of the iterative inversion process comprises:
simultaneous encoded-source simulation of survey data representing a plurality of survey sources, or receivers if source-receiver
reciprocity is used,

wherein source or receiver signatures in the simultaneous encoded-source simulation are encoded, resulting in a simulated
simultaneous encoded-source or encoded-receiver gather of geophysical data,

the iterative inversion process involving updating the initial physical properties model to reduce misfit between the simulated
simultaneous encoded-source or encoded-receiver gather and

a corresponding simultaneous encoded-source or encoded-receiver gather formed by summing gathers of measured survey data encoded
with the same encoding functions used in the simultaneous encoded-source simulation, and

the updating includes determining an update to the initial physical properties model from a gradient of a cost function characterizing
the misfit with respect to a parameter that describes the initial physical properties model and perturbing the initial physical
properties model in direction of the gradient, and

(ii) at least one iteration of the iterative inversion process is performed by sequential source or receiver inversion;
(c) downloading the updated physical properties model or saving it to computer storage; and
(d) generating a subsurface image from the further updated physical properties model.

1. A method of modeling drilling equipment comprising:
constructing two or more design configurations, wherein each of the design configurations represents at least a portion of
a bottom hole assembly (BHA);

identifying operating parameters for the two or more design configurations;
selecting lateral model mathematical boundary conditions for a lateral beam bending mathematical model that provide system
excitation through a lateral mode, wherein the two or more design configurations are subjected to identical lateral system
excitation;

calculating lateral beam bending results using the lateral beam bending mathematical model in a computer processor accessing
non-transitory computer readable media, for each of the two or more design configurations using the identified operating parameters
and the selected mathematical boundary conditions;

comparing the calculated results for the two or more design configurations;
displaying the calculated results of at least one of the two or more design configurations;
selecting operating parameters for at least a portion of a bottom hole assembly design configuration, based on the calculated
results for the two or more design configurations, and selecting at least a portion of the bottom hole assembly design configuration,
based on the selected operating parameters; and

drilling a well with drilling equipment based at least on the selected bottom hole assembly design configuration.

1. A power delivery system, comprising:
two or more rectifiers electrically coupled to an AC power source and configured to generate a direct current;
a transformer coupled to the AC power source and comprising two or more output windings to convert current from the AC power
source to a multiphase AC signal, wherein each of the two or more output windings is coupled to an input of one of the two
or more rectifiers, and wherein phases of the multiphase AC signal are out of phase with one another by a specified displacement
angle; and

two or more inverters configured to receive the direct current and generate an alternating current waveform for powering a
load;

wherein the two or more rectifiers and the two or more inverters are coupled in series with each other through an inductor;
and further comprising

a DC bus comprising an upper rail and a lower rail, wherein the two or more rectifiers are coupled in series with each other
between the upper rail and the lower rail and the two or more inverters are coupled in series with each other between the
upper rail and the lower rail;

wherein a positive output terminal of one of the rectifiers is directly coupled to a negative output terminal of a different
one of the rectifiers; and wherein

a positive input terminal of one of the inverters is directly coupled to a negative input terminal of a different one of the
inverters.

1. A method of performing a simulation of a subsurface hydrocarbon reservoir, the reservoir being approximated by a reservoir
model having a plurality of cells, each cell having associated therewith an equation set representing a reservoir property,
the method comprising:
(a) determining a stability limit for each of the plurality of cells;
(b) assigning each cell to one of an explicit formulation or an implicit formulation;
(c) providing an initial guess to a solution for a system of equations formed using the equation set for each cell in the
plurality of cells;

(d) using the initial guess to solve for a solution to the system of equations using an explicit formulation for cells assigned
thereto and an implicit formulation for cells assigned thereto;

(e) establishing a list of unconverged cells, the unconverged cells having equation sets that have not satisfied a convergence
criterion;

(f) calculating a stability limit for each of the converged cells, the converged cells having equation sets that have satisfied
the convergence criterion;

(g) when the number of unconverged cells is greater than a predetermined amount, constructing a reduced nonlinear system with
the list of unconverged cells, the reduced nonlinear system being assigned to be solved with the implicit formulation and
other cells being assigned to be solved with the explicit formulation;

(h) repeating parts (d), (e), (f) and (g), substituting the solved solution for the initial guess or the most recent solved
solution and substituting the equation sets corresponding to the cells in the list of unconverged cells for the system of
equations or equation sets from the most recent iteration, until all equation sets satisfy the convergence criterion and a
stability criterion; and

(i) when all equation sets satisfy the convergence criterion and the stability criterion, outputting the solved solution as
a result for a timestep of a simulation of the subsurface reservoir.

1. A method of disposing of fluids produced from a wellbore extending from a wellbore surface into a subsurface formation, the subsurface formation having a production zone and a disposal zone, at least a portion of the wellbore lined with a string of casing, comprising:placing a wellbore tubular conduit within the casing forming an annulus between the tubular conduit and the casing:
placing a pump in fluid communication with the wellbore tubular conduit, the pump having an inlet and a discharge, the inlet in fluid communication with a source of produced fluids; and
injecting the produced fluids through a plurality of perforations positioned about the casing into a disposal zone of the subsurface formation using the pump, without pumping any of the produced fluids to the surface;
powering the pump only for injecting the produced fluids into the disposal zone; and
producing gas from the formation through the annulus to the wellbore surface using subsurface formation pressure while injecting the produced fluids.

1. A method of generating a three-dimensional reservoir model simulation grid and extracting hydrocarbons from a subsurface earth volume comprising:a) first, providing, with a computer system, a geological model comprising horizons, modeling constraints and multiple geological grid cells and a plurality of pillars, wherein the geological model is a representation of the subsurface earth volume in three dimensions;
b) second, constructing, with the computer system, a pre-image corresponding to the multiple geological grid cells, said pre-image comprising a two dimensional surface representative of areal geometry of the geological model, said modeling constraints being mapped onto said two dimensional surface;
c) third, generating, with the computer system, a constrained two-dimensional grid on the pre-image with the computer system, the constrained two-dimensional grid comprising multiple grid cells;
d) fourth, selecting, with the computer system, simulation layer boundaries associated with a plurality of simulation layers from said geological model and projecting the constrained two-dimensional grid onto said simulation layer boundaries, wherein the constrained two-dimensional grid cells comprise identifiers corresponding to the grid cells of the geological model, wherein the grid cells are projected along k-direction lines of the multiple geological grid cells, wherein each k-direction line is along one of the plurality of pillars, and wherein each of the plurality of simulation layers is comprised of major depositional surfaces that are nearly horizontal, fault surfaces which can have arbitrary spatial size and orientation, or detailed stratigraphic layers;
e) fifth, generating, with the computer system, prismatic cells from the constrained two-dimensional grid to form the three-dimensional reservoir model simulation grid;
f) sixth, outputting, with the computer system, the three-dimensional reservoir model simulation grid;
g) seventh, predicting, with the computer system, presence or location of hydrocarbons, or predicting or estimating an extraction location in the subsurface earth volume; and
h) eighth, extracting hydrocarbons based on the three-dimensional reservoir model simulation grid using oil drilling equipment.

1. A method of recovering heavy oil from a subterranean reservoir, the method comprising:
injecting steam into a subterranean reservoir to heat heavy oil in the subterranean reservoir and produce heavy oil, the heavy
oil in the subterranean reservoir having a first viscosity and the heavy oil produced having a reduced viscosity that is lower
than the first viscosity;

injecting a multi-purpose agent into said subterranean reservoir;
diluting the heavy oil with the multi-purpose agent until a ratio of the multi-purpose agent to the heavy oil is between 1:19
to 1:1 by weight;

producing said heavy oil of reduced viscosity from said subterranean reservoir after injecting the steam and the multi-purpose
agent;

wherein the multi-purpose agent comprises an ester of the formula:
RxCOORy
wherein:
Rx is a straight chained or branched alkyl group having 1 to 8 carbon atoms,

Ry is a straight chained or branched alkyl group having 1 to 12 carbon atoms,

C is carbon, and
O is oxygen.

1. A method of backfilling a subsurface formation comprising:
forming a mixture of tailings from at least a first tailings stream and a second tailings stream, wherein the first tailings
stream and second tailings stream are produced from one or more hydrocarbon recovery processes and have different particle
size distributions and the mixture is comprised of a fluid;

varying the fluid content of the mixture to control the rheology of the mixture; and
injecting the mixture having the controlled rheology through a pipe into the subsurface formation;
wherein the permeability of the mixture is between about 0.01 and about 10 times an initial permeability of a material in
a subsurface formation.

1. A method for completing a wellbore in a subsurface formation, the method comprising:
providing a packer, the packer comprising:
an inner mandrel,
alternate flow channels along the inner mandrel,
a movable piston housing retained around the inner mandrel,
one or more flow ports providing fluid communication between the alternate flow channels and a pressure-bearing surface of
the piston housing, and

a sealing element external to the inner mandrel;
connecting the packer to a tubular body;
running the packer and connected tubular body into the wellbore;
running a setting tool into the inner mandrel of the packer;
manipulating the setting tool to mechanically release the movable piston housing from its retained position;
setting the packer by communicating hydrostatic pressure to the piston housing through the one or more flow ports, thereby
moving the released piston housing to actuate the sealing element into engagement with the surrounding wellbore;

injecting a gravel slurry into an annular region formed between the tubular body and the surrounding wellbore; and
injecting the gravel slurry through the alternate flow channels to allow the gravel slurry to at least partially bypass the
sealing element so that the wellbore is gravel-packed within the annular region below the packer.

1. A device for high speed hydraulic actuation, the device comprising:
an actuator;
a hydraulic pressure regulator including a hydraulic pressure input port, an opposing pressure input port, and a vent port,
the hydraulic pressure regulator used to adjust the hydraulic pressure on the actuator which adjusts a position of the actuator;

a pressure sensing line allowing an output pressure of the actuator to feed the opposing pressure input port to balance the
hydraulic pressure input port;

a first solenoid configured to increase pressure on the hydraulic pressure input port of the hydraulic pressure regulator
to increase hydraulic pressure on the actuator, opening the actuator;

a second solenoid configured to decrease pressure on the hydraulic pressure input port of the hydraulic pressure regulator
to decrease hydraulic pressure on the actuator, closing the actuator; and

a control valve configured to be moved in response to the position of the actuator.

1. A method for partitioning a reservoir, comprising:
generating a representation of a topology graph of a simulation model in a non-transitory computer readable medium, wherein
the topology graph comprises a plurality of elements and a plurality of connections between adjacent elements;

weighting, using a computer, each of the plurality of connections to create a plurality of weights, wherein one or more of
the plurality of weights are non-integers selected from any real values, wherein the plurality of elements comprise computational
cells in a computational mesh and wherein the weighting of each of the plurality of connections is based, at least in part,
on physical properties assigned to the computational cells, and wherein the physical properties comprise transmissibility,
total mobility, mass flow, heat flow, or any combinations thereof;

scaling, using the computer, each of the plurality of weights, wherein the scaled plurality of weights are integer values,
and wherein scaling comprises nonlinear monotone mapping the one or more non-integer weights into corresponding integer values;

partitioning, using the computer, the topology graph into two or more subdomains, wherein a partition boundary follows a local
topographical minimum in the topology graph; and

assigning a subdomain to each of a plurality of processors.

1. A method for determining a bedding surface from an azimuthal image made from a signal provided by a logging tool placed
in a cylindrical wellbore, said method comprising:
determining, using a computer and based on minimum variance, a best sine wave in the the minimum variance represents a minimum
value in a variance map of sine waves of the azimuthal image;

computing contrast at each selected depth along the best sine wave in the azimuthal image; and
locating one or more bedding surface boundaries at one or more depths with highest contrasts.

1. A method for acquiring near zero-offset seismic data said method comprising:
towing a seismic source array and a plurality of streamers in a 3D survey configuration,
wherein the plurality of streamers are towed separately from the seismic source array, the 3D survey configuration includes
a plurality of acoustic transmitters, a separate acoustic transmitter, relative to the seismic source array, of the plurality
of acoustic transmitters, is suspended below a head or tail of each of the plurality of streamers, and each of the plurality
of streamers and the acoustic transmitter corresponding thereto are suspended from a buoy;

firing at least one of the plurality of acoustic transmitters, wherein the firing causes an acoustic signal to penetrate beneath
the water bottom at least 300 m into earth's subsurface; and

obtaining the near zero-offset seismic data from one or more streamer sensors nearest the at least one of the plurality of
acoustic transmitters, wherein the streamer sensors record a reflection of the acoustic signal from a structure in the earth's
subsurface.

1. A method, comprising:
identifying a well target or reservoir segment;
defining a dynamic surface grid in a computer system, the dynamic surface grid being a representation of a ground surface,
sea-level, or subsea surface above a reservoir upon which a drill center is locatable, and the dynamic surface grid including
a plurality of cells that define potential locations for the drill center;

creating a first attribute map with a first drilling or geologic attribute in combination with a first well target or reservoir
segment;

creating a second attribute map with the first drilling or geologic attribute in combination with a second well target or
reservoir segment in the reservoir;

creating a first composite attribute map by combining the first attribute map and the second attribute map;
assigning, to each of the plurality of cells of the dynamic surface grid in the computer system, a value of a drilling or
geologic attribute from the first composite attribute map that defines a quality of a drill center position relative to the
well target or reservoir segment;

selecting, based on a value of the drilling or geologic attribute, a location for the drill center corresponding to a location
represented on the dynamic surface grid;

displaying the selected location for the drill center; and
causing a well to be drilled at the location of the drill center for the production of hydrocarbons.

1. A method for separating carbon dioxide from heavy hydrocarbons, comprising:
cooling a first liquid stream comprising carbon dioxide and heavy hydrocarbons within an oscillatory crystallization unit
to generate carbon dioxide solids and a second liquid stream comprising the heavy hydrocarbons; and

separating the carbon dioxide solids from the second liquid stream via a solid-liquid separation system.

19. A adsorbent bed assembly comprising:
a housing having an interior region and configured to maintain a pressure from 0 bar to 80 bar within the interior region;
an adsorbent bed disposed in the interior region and having a plurality of flow channels through the adsorbent bed, wherein
the plurality of flow channels have an adsorbent material disposed on at least one surface within the plurality of flow channels;

an inlet conduit disposed adjacent to the adsorbent bed and configured to pass a stream into the interior region from a location
external to the housing;

an outlet conduit disposed adjacent to the adsorbent bed and configured to pass a stream into the interior region from a location
external to the housing; and

a plurality of equalization vessels in fluid communication with the interior region and dedicated to the adsorbent bed.

1. A system, comprising:
an exhaust gas path configured to receive at least a portion of an exhaust gas provided by a gas turbine;
an exhaust gas scrubber fluidly coupled to the exhaust gas path;
a moisture separator fluidly coupled to the exhaust gas path; and
a cooling circuit fluidly coupled to the exhaust gas path downstream from the exhaust gas scrubber and the moisture separator,
wherein the cooling circuit is configured to fluidly couple to a plurality of cooling paths through the gas turbine, wherein
the plurality of cooling paths is separate from a working fluid path through the gas turbine, wherein the cooling circuit
comprises a flow distribution header and a compressor fluidly coupled to the flow distribution header, wherein the compressor
is separate from the flow distribution header, and the flow distribution header is configured to distribute the exhaust gas
to the plurality of cooling paths through the gas turbine, and wherein the flow distribution header comprises at least one
setting that enables simultaneous distribution of the exhaust gas to at least two cooling paths of the plurality of cooling
paths.

1. A method for obtaining a subsurface image from seismic data, comprising:
migrating, using a computer, individual traces of the seismic data, without any stacking of offsets and assembling of midpoints,
wherein the individual traces are earth's response to seismic waves originating from a source as recorded by a receiver;

performing at least one processing technique on the migrated individual traces, using a computer, resulting in processed data
still in offset-midpoint domain; and

forming and displaying, with a computer, a seismic image of the subsurface directly from the processed migrated individual
traces in the offset-midpoint domain, wherein the forming includes at least partially stacking of offsets and assembling of
midpoints separately from the migrating, and the seismic image identifies location of structure in earth's subsurface that
returned the seismic waves to receivers that recorded the seismic data.

26. A method of regulating a temperature of an active pyrolysis region within a subterranean formation, the method comprising:
supplying thermal energy to the subterranean formation to heat the active pyrolysis region of the subterranean formation and
to generate a product fluid stream therefrom;

producing the product fluid stream from the subterranean formation via a production well that extends between a surface region
and the subterranean formation;

detecting a concentration of a temperature-sensitive component in the product fluid stream, wherein the concentration of the
temperature-sensitive component is indicative of a temperature of the active pyrolysis region; and

regulating a rate of the supplying thermal energy based, at least in part, on the concentration of the temperature-sensitive
component.

1. A method of detecting at least one chemical species comprising:
obtaining at least a first image from a first electromagnetic radiation detector configured to detect the chemical species,
the first image including a first plurality of pixels, each pixel having an associated intensity value;

obtaining at least a second image from a second electromagnetic radiation detector configured to provide a reference background,
the second image including a second plurality of pixels, each pixel having an associated intensity value;

generating at least a first resultant image by determining the difference in intensity values between each of the first plurality
of pixels of the first image and the corresponding pixels of the second plurality of pixels of the second image, using the
difference in intensity as the intensity value for the corresponding plurality of resultant pixels of the first resultant
image;

determining one or more regions of interest based, at least in part, on the first resultant image;
determining correlation between the first image, the second image, and the first resultant image for at least one of the one
or more regions of interest using a correlation coefficient algorithm to:

calculate a first correlation coefficient using the intensity values of a first subset of pixels from the first plurality
of pixels and a corresponding subset of resultant pixels from the plurality of resultant pixels within at least one of the
one or more regions of interest, and

calculate a second correlation coefficient using the intensity values of a first subset of pixels from the second plurality
of pixels and the corresponding subset of resultant pixels from the plurality of resultant pixels within the corresponding
region of interest; and

determining the presence of at least one chemical species based, at least in part, on the first correlation coefficient and
the second correlation coefficient.

1. A cyclic solvent-dominated recovery process for recovering hydrocarbons from an underground reservoir, the cyclic solvent-dominated
recovery process comprising:
(a) injecting injected fluid comprising greater than 50 mass % of a viscosity-reducing solvent into an injection well completed
in the underground reservoir;

(b) halting injection into the injection well and subsequently producing at least a fraction of the injected fluid and the
hydrocarbons from the underground reservoir through a production well;

(c) halting production through the production well; and
(d) repeating the cycle of steps (a) to (c);
wherein step (a) comprises, in at least one cycle, contacting uncovered hydrocarbons between solvent fingers by (a1) alternating
injection of the injected fluid and production of at least a fraction of the injected fluid and the hydrocarbons to create
an advance-retreat movement of the injected fluid; and

wherein (a1) is performed in a given injection (a) at some point after 25% of pore volume has been injected and production
volume in (a1) is less than 25% of production volume in (c) in a given cycle (a) to (c).

1. An apparatus comprising:
a tubular suction pile;
an indenter housing that surrounds the tubular suction pile,
wherein the indenter housing is configured to be sunk into a seabed in response to a negative pressure created from water
being removed from the tubular suction pile, and the indenter housing is configured to create a trench in the seabed; and

a water jetting device, within the indenter housing, that includes a first valve, a nozzle, and
a channel that connects the first valve to the nozzle.

1. A method for heating a subsurface formation using electrically resistive heat, comprising:
providing a first wellbore at least partially within a subsurface formation, the first wellbore having an electrically conductive
first member, an electrically conductive second member, and an electrically conductive first granular material in the first
wellbore, wherein the first granular material is positioned to provide electrical communication between the electrically conductive
first member and the electrically conductive second member, wherein the electrically conductive first member consists of an
elongated rod, wire or cable and the electrically conductive second member consists of an elongated rod, wire or cable, wherein
the electrically conductive first member terminates at a first depth within the subsurface formation and the electrically
conductive second member terminates at a second depth that is lower than the first depth and within the subsurface formation,
and wherein neither the electrically conductive first member nor the electrically conductive second member is in electrical
contact with a well casing;

providing a second wellbore at least partially within the subsurface formation, the second wellbore having an electrically
conductive third member, an electrically conductive fourth member, and an electrically conductive second granular material
in the second wellbore, wherein the second granular material is positioned to provide electrical communication between the
electrically conductive third member and the electrically conductive fourth member, wherein the electrically conductive third
member consists of an elongated rod, wire, or cable and the electrically conductive fourth member consists of an elongated
rod, wire, or cable, wherein the electrically conductive third member terminates at a third depth within the subsurface formation
and the electrically conductive fourth member terminates at a fourth depth that is lower than the third depth and within the
subsurface formation, and wherein neither the electrically conductive third member nor the electrically conductive fourth
member is in electrical contract with a well casing;

passing a first electrical current through the electrically conductive first member, the first granular material and the electrically
conductive second member, thereby generating first heat, the generated first heat produced primarily through electrical resistive
heating of the first granular material wherein the first electrical current flows down the first wellbore through the electrically
conductive second member and then up the first wellbore through the electrically conductive first member;

passing a second electrical current through the electrically conductive third member, the second granular material and the
electrically conductive fourth member, thereby generating second heat, the generated second heat produced primarily through
electrical resistive heating of the second granular material wherein the second electrical current flows down the second wellbore
through the electrically conductive third member and then up the second wellbore through the electrically conductive fourth
member; and

heating formation hydrocarbons located substantially equidistant from the first wellbore and the second wellbore primarily
with the generated first heat, second heat or both.

1. A testing apparatus for simulating stratified or dispersed flow dynamics, comprising:
an outer housing configured to hold a multi-phase mixture comprising an upper phase and a lower phase, wherein the upper phase
and the lower phase are immiscible liquids;

a rotor drum connected to a rotor shaft, wherein a bottom surface of the rotor drum is in contact with a top surface of the
upper phase;

the rotor shaft configured to rotate the rotor drum;
an inner drum configured to function as an inner boundary for the multi-phase mixture; and
a bottom end cap configured to hold at least one instrument configured to monitor a parameter of the multi-phase mixture.

1. A method for enhancing the shear stability of a high-viscosity fluid-water biphasic flow system, comprising:
injecting an additive into the biphasic flow system, the additive comprising a salt of a polynuclear aromatic sulfonic acid,
wherein the biphasic flow system is a core annular flow system,

wherein the addictive is mixed with a solvent as a delivery carrier, and the solvent includes one of crude oil distillates
boiling in the range of about 70° C. to about 450° C., alcohols, ethers, and any mixtures thereof.

1. A method for separating components of a slurry, the method comprising:
flowing a slurry stream that includes the slurry through a slurry conduit defined by a body, wherein the slurry conduit is
in fluid communication with a first perforated region and a second perforated region, and further wherein the slurry includes
a liquid and a plurality of solid particles;

injecting a displacing fluid through the first perforated region and into the slurry conduit as a displacing fluid stream;
displacing at least a portion of the liquid from the slurry with the displacing fluid stream to create a product slurry stream
that includes at least a portion of the injected displacing fluid and at least a portion of the plurality of solid particles;
and

producing a displaced fluid stream from the slurry conduit through the second perforated region, wherein the displaced fluid
stream includes at least a portion of the displacing fluid and at least a portion of the liquid from the slurry;

wherein at least one of the first perforated region and the second perforated region includes one of (i) at least one of a
wire mesh, a metal screen, a sintered metal, a porous ceramic, and cemented rock and (ii) is in fluid communication with a
flow port.

1. A system, comprising:
a turbine combustor, comprising:
a head end portion having a head end chamber;
a combustion portion having a combustion chamber disposed downstream from the head end chamber;
a cap disposed between the head end chamber and the combustion chamber; and
a flow distributor comprising a plurality of flow distributor portions spaced circumferentially around the head end portion,
and including a first flow distributor portion and a second flow distributor portion, wherein each flow distributor portion
of the plurality of flow distributor portions is configured to receive an oxidant flow from an oxidant source and to route
the oxidant flow axially along the head end portion;

wherein the first flow distributor portion comprises a first exhaust gas flow path configured to receive a first compressed
exhaust gas flow and to route the first compressed exhaust gas flow radially inward to a cooling region adjacent the cap;
and

wherein the second flow distributor portion comprises a second exhaust gas flow path configured to receive a second compressed
exhaust gas flow and to route the second compressed exhaust gas flow radially outward to extract the second compressed exhaust
gas flow from the turbine combustor.

1. A method for transporting a hydrocarbon through a pipeline, comprising:
injecting water into a production stream at a production center, wherein the production stream comprises a hydrocarbon, and
wherein the water injection forms a transportation stream comprising a water external phase;

promoting the formation of hydrates around oil droplets and hydrates around gas bubbles, wherein the gas bubbles comprise
light hydrocarbons, wherein the hydrates, oil droplets, gas bubbles, and water form a transportable hydrate slurry, and wherein
promoting comprises:

creating the transportable hydrate slurry, wherein creating comprises flowing the transportation stream through a static mixer;
isolating wax in the oil droplets by cooling the transportable hydrate slurry below a wax appearance temperature or a hydrate
formation temperature, wherein cooling comprises contacting the transportable hydrate slurry with the pipeline, flowing the
transportable hydrate slurry through a heat exchanger, or both; and

maintaining the transportable hydrate slurry, wherein maintaining comprises:
flowing the transportation stream through a plurality of static mixers;
monitoring a phase behavior of the transportation stream, the size of the hydrate particles, or both; and
controlling the phase behavior in the transportation stream by adding a thermodynamic hydrate inhibitor to keep the water
external phase, and wherein the thermodynamic hydrate inhibitor suppresses capillary attractive forces between hydrate particles;
and

flowing the transportation stream through a transportation line to a surface facility.

1. An electro-acoustic telemetry system for monitoring fluid flow in a wellbore, the wellbore penetrating into a subsurface
formation, and the telemetry system comprising:
a production tubing disposed in the wellbore, the production tubing being comprised of threadedly-connected pipe joints;
one or more gas lift valves placed along the production tubing;
at least one sensor disposed along the production tubing adjacent each of the one or more gas lift valves, each sensor designed
to measure a parameter indicative of fluid flow within the production tubing adjacent the one or more gas lift valves;

one or more sensor communications nodes associated with and in electrical communication with one of the at least one sensors
and configured to receive signals from the associated sensor indicative of fluid flow;

a topside communications node placed along the wellbore proximate a surface;
a plurality of intermediate communications nodes spaced along the wellbore and attached to a pipe string, the intermediate
communications nodes including a transceiver in acoustic contact with the production tubing and configured to transmit acoustic
waves from node-to-node along the wellbore using the production tubing as a transmission medium for the acoustic waves from
the one or more sensor communications nodes to the topside communications node; and

wherein each of the intermediate communications nodes comprises:
a sealed housing;
an electro-acoustic transducer and associated transceiver residing within the housing, with the transceiver being designed
to relay signals from node-to-node up the wellbore, with each signal representing a packet of information that comprises an
acoustic waveform representing fluid flow data; and

an independent power source residing within the housing providing power to the transceiver.

1. A method for installing a lower pipe-conforming structure on a pipeline, the method comprising:
disposing the lower pipe-conforming structure along an external length of the pipeline, the lower pipe-conforming structure
comprising a polymer material and one or more optic fibers embedded within the polymer material;

conforming the lower pipe-conforming structure to the shape of the pipeline; and
attaching the lower pipe-conforming structure to the pipeline proximate to the bottom of the pipeline, wherein the lower pipe-conforming
structure covers an angle of a pipe circumference of between about 100° and about 180°.

1. A method for evaluating annulus-tubing communication points in a production well, the production well having one or more strings of casing extending below a surface, and a string of production tubing within the strings of casing thereby forming an annulus, and the method comprising:placing up to 1,000 cc's of each of two or more tracer materials into a portable, hand-held vessel;
causing the two or more tracer materials to be injected from the vessel into the annulus of the well under pressure as part of a lift gas, wherein each of the two or more tracer materials defines a material that is not native to the production fluids;
further injecting the lift gas in order to cause each of the two or more tracer materials to contact the annulus-tubing communication points residing along the production tubing, and to enter the production tubing;
producing formation fluids along with lift gas and the two or more tracer materials to the surface;
detecting the two or more tracer materials at the surface by using a fluid analyzer, wherein the fluid analyzer is capable of detecting the two or more tracer materials at concentrations of less than 1,000 ppm; and
measuring a concentration of each of the two or more tracer materials in the produced fluids as a function of time.

1. A bridge plug arrangement, comprising:
a plug having an upper end, a bottom end, and a beveled edge along an outer diameter proximate the bottom end of the plug;
a tubular member for receiving the plug, the tubular member having an upper end, a bottom end, and a bore extending from the
upper end to the bottom end;

a shoulder disposed along an inner diameter of the tubular member below said upper end and configured to receive the beveled
edge of the plug; and

one of a bore defined by a body of the plug, the bore extending from the upper end to the bottom end and configured to receive
a running tool, or a hook extending from the upper end and configured to receive a running tool;

wherein the plug and is fabricated of frangible material.

1. A method for detecting hydrocarbons comprising:
performing a remote sensing survey of a survey location;
analyzing the remote sensing data from the remote sensing survey to determine a target location;
deploying an underwater vehicle (UV) into a body of water;
navigating the UV within the body of water to the target location;
obtaining measurement data within the body of water at the target location, wherein measurement components on the underwater
vehicle measure molecular and isotopic signatures of non-hydrocarbon gases and hydrocarbons in the body of water at the target
location and wherein measuring the isotopic signature of hydrocarbons includes measuring the signature of clumped isotopologues
in a sample from the body of water; and

determining whether hydrocarbons are present at the target location based on the measurement data.

1. A method of drilling a wellbore, the method comprising:
receiving surface measurement data regarding drilling parameters characterizing ongoing wellbore drilling operations, wherein
at least one of the drilling parameters is controllable;

determining rate of penetration (ROP) and mechanical specific energy (MSE) utilizing the received surface measurement data;
utilizing a computer processor to calculate

(i) a drilling performance measurement embodied in an objective function comprising a relationship between the determined
ROP and the determined MSE, wherein the objective function comprises at least one of;

wherein ? factor is added to the objective function to avoid a trivial denominator, SS is the stick slip severity, ROP0, MSE0 and SS0 are the nominal values for ROP, MSE and SS and are used in the objective function to provide dimensionless values, and ?ROP,
?MSE and ?SS are changes in ROP, MSE and SS between a current and a previous time step, or between a current and a previous
depth location, and torsional SS can be either real time stick slip measurements transmitted from a downhole vibration measurement
tool or a model prediction calculated from a surface torque and a drillstring geometry; and
(ii) a mathematical correlation between the at least one controllable drilling parameters and the calculated drilling performance
measurements of step (i);
generating operational recommendations based upon the mathematical correlation for the at least one controllable drilling
parameter; wherein the operational recommendations are selected to optimize the objective function of (i);determining operational updates to the at least one controllable drilling parameter based at least in part on the generated
operational recommendations; andimplementing at least one of the determined operational updates in the ongoing drilling operations.

1. A method for estimating source signature of a marine seismic source array in a naturally band-limited subsurface region,
for subsequent processing of resulting seismic data, comprising:
obtaining a signal record from at least one seismic receiver deployed in the source array's far field, and identifying direct
arrivals from the source array in the signal record; and

generating a far-field estimate of the source signature by using a computer to process the direct arrivals to enhance them
and to compensate for surface ghosting or receiver streamer array effects or both, wherein the direct arrivals used to generate
the far-field estimate of the source signature were recorded by the at least one seismic receiver deployed in the source array's
far field.

1. A computer-implemented method for inverting seismic data to obtain reflection properties of a subsurface region, comprising:
estimating or measuring a source signature for the seismic data; and
using the source signature, inverting the seismic data simultaneously for a subsurface formation or reflection property and
for amplitude attenuation or velocity dispersion effects or both, integrated over a ray-path from source to reflectors and
to a receiver;
wherein, at least the inversion is performed using a computer, and the inversion transforms the seismic data into an interpretable
model of the subsurface region.

1. A method for analyzing a geophysical data volume obtained or derived from a geophysical survey of a subsurface region to
determine physical structure of the subsurface region, comprising: (a) dividing the data volume into a plurality N of initial
segments, at least one segment being greater than one voxel in size, a voxel being a single data point in the data volume;
(b) successively combining pairs of segments until the number of segments is reduced to a selected number M, where M (c) creating a record of hierarchical multiresolution segmentations by recording stages of successively combined pairs from
the plurality of N initial segments to the reduced number of M segments;

(d) analyzing some or all of either the M segments, or segments from an intermediate stage of combination, to interpret subsurface
physical structure, wherein the analyzing includes zooming in and out of the geophysical data volume by using the stages of
the successively combined pairs that were recorded to retrieve and display at least one image of the geophysical data volume
with a number of segments ranging from the N initial segments to the M segments;

(e) evaluating the interpreted subsurface physical structure within the displayed at least one image for hydrocarbon accumulations;
and

(f) causing a well to be drilled;
wherein analyzing the M segments comprises highgrading, ranking, or prioritizing the M segments based on one or more measures
selected from geometrical properties of an arrangement of pixels that form the M segments in the at least one image, direct
hydrocarbon indicators, and collocated property measures that are built by querying a seismic or attribute dataset at locations
within the seismic or attribute data set that are collocated with locations of the M segments in the geophysical data volume,
and wherein the method further comprises using the one or more measures after a plurality of stages of combination to stop
the successively combining pairs of segments.

1. A method for production of hydrocarbons, comprising:
forming a cavern using solution mining;
flowing a stream directly from a hydrocarbon reservoir to the cavern without reaching a surface;
performing phase separation of the stream within the cavern to form an aqueous phase and an organic phase;
flowing at least a portion of the organic phase directly from the cavern to a separate subsurface location without reaching
the surface; and

offloading at least a portion of the organic phase from the cavern to the surface.

1. A method of generating a horizon surface based on multiple candidate horizon surfaces, the method comprising:
selecting seeds that represent different starting locations within a desired horizon surface;
generating a plurality of candidate horizons from the selected seeds;
generating the horizon surface by combining, for each point on the horizon surface, depth values from corresponding points
on the plurality of candidate horizons into a single representative depth value;

computing an uncertainty for each point on the horizon surface based on a difference between two or more depth values from
the plurality of candidate horizons that create the single representative depth value, respectively; and

creating a model of the subsurface region using the horizon surface.

1. A method for modeling a hydrocarbon reservoir, comprising:
generating a reservoir model comprising a plurality of coarse grid cells;
generating a plurality of fine grid models, each fine grid model corresponding to one of the plurality of coarse grid cells
that surround a flux interface;

simulating the plurality of fine grid models using a training simulation to obtain a set of training parameters comprising
a potential at each coarse grid cell surrounding the flux interface and a flux across the flux interface;

using a machine learning algorithm to generate a constitutive relationship that provides a solution to fluid flow through
the flux interface;

simulating the hydrocarbon reservoir using the constitutive relationship; and
generating a data representation of a physical hydrocarbon reservoir in a non-transitory, computer-readable medium based,
at least in part, on the results of the simulation, wherein the constitutive relationship generated for the flux interface
is re-used for a second flux interface based on a comparison of a set of physical, geometrical, or numerical parameters corresponding
to the flux interface and a new set of physical, geometrical, or numerical parameters that characterize the second flux interface;
and

producing a hydrocarbon from the hydrocarbon reservoir based, at least in part, upon the results of the simulation.

1. A process for liquefying a gas stream, said process comprising:
(a) providing said gas stream at a pressure of from 600 to 1,000 psia (4,137-6,895 kPa) as a feed gas stream;
(b) providing a refrigerant at a pressure of less than 1,000 psia (6,895 kPa) by withdrawing a portion of said gas stream
for use as said refrigerant;

(c) compressing said refrigerant in a closed loop to a pressure greater than or equal to 1,600 to less than or equal to 5,000
psia (11,032 to 34,474 kPa) to produce a compressed refrigerant;

(d) cooling said compressed refrigerant by indirect heat exchange with a cooling fluid;
(e) expanding the compressed refrigerant of (d) to cool said compressed refrigerant, to produce an expanded, cooled refrigerant
at a pressure of from greater than or equal to 100 psia (689 kPa) to less than or equal to 1,000 psia (6895 kPa);

(f) passing said expanded, cooled refrigerant to a first heat exchange area;
(g) compressing the feed gas stream of (a) to a pressure of from greater than or equal to 2,500 psia (17,237 kPa) to less
than or equal to 3,500 psia (24,132 kPa) to produce a compressed feed gas stream;

(h) cooling said compressed feed gas stream by indirect heat exchange with an air or water refrigerant cooler;
(i) passing said compressed feed gas stream through the first heat exchange area to cool at least a part thereof by indirect
heat exchange, to produce a compressed, further cooled feed gas stream, wherein the feed gas is used as the only refrigerant
such that no external refrigerants are used, except for water or air;

(j) passing the compressed, further cooled feed gas stream of (i) through a second heat exchange area for extra cooling; and
(k) expanding said compressed, further cooled feed gas stream of (j) to reduce the pressure of said compressed, further cooled
feed gas stream to a pressure of from greater than or equal to 50 psia (345 kPa) to less than or equal to 450 psia (3103 kPa)
to produce an expanded, cooled gas stream; and

(l) withdrawing a portion not to exceed 50% of said expanded, cooled gas stream of (k) and reducing its pressure in a reduction
valve to a range of about 30-200 psia (207-1379 kPa) to produce a reduced pressure gas stream and passing the reduced pressure
gas stream through the second heat exchange area of (j) as a cooling gas stream.

1. A method for managing an oil release, comprising:
towing at least one boom, at least one floating burner and at least one oleophilic skimmer from a marine vessel through a
body of water;

containing oil in the body of water within the at least one boom;
capturing a fluid within the boom via the at least one oleophilic skimmer;
passing the captured fluid via tubing to the at least one floating burner; and
combusting at least a portion of the captured fluid via the at least one floating burner, wherein the at least one floating
burner includes a floatation section and a burner section, the burner section positioned on the floatation section above a
surface of the body of water, the burner section including a captured fluid injection line in fluid communication with the
tubing.

1. A subsea multiphase separation system, comprising:
an inlet line;
a divide, wherein the divide horizontally splits the inlet line into two or more separate lines of similar diameter, and wherein
the two or more separate lines of similar diameter are substantially parallel to one another, and are configured to separate
components of a multiphase fluid;

a control volume connected to the two or more separate lines of similar diameter, wherein the control volume has a diameter
greater than the separate lines of similar diameter, wherein the control volume comprises outlet lines, and wherein the outlet
lines are configured to flow substantially oil from an upper outlet line and flow substantially water from a lower outlet
line; and

a sand boot connected to one of the separate lines of similar diameter, wherein the sand boot is disposed below the one of
the separate lines of similar diameter, and wherein the sand boot is configured to collect and remove sand accumulated in
the subsea multiphase separation system; and

a jet nozzle, disposed within one of the separate lines of similar diameter and connected to the lower outlet line of the
control volume, the jet nozzle being positioned at an injection point upstream of the sand boot such that fluid from the lower
outlet line is injected into the sand boot to activate a sand removal cyclone which fluidizes sand in the sand boot, the sand
removal cyclone causing the sand to be removed from the sand boot without shutdown or slowdown of production of the subsea
multiphase separation system.

1. A method of completing a well that averts occurrence of a hydraulic fracturing screen-out condition, comprising:forming a wellbore, the wellbore comprising a bore extending into a subsurface formation;
lining at least a lower portion of the wellbore with a string of production casing;
placing a first valve along the production casing releasably secured in a closed position, the valve creating a removable barrier to fluid flow within the bore;
perforating the production casing along a first zone of interest within the subsurface formation, the first zone of interest residing at or above the valve, wherein perforating the production casing comprises;
pumping an autonomous perforating gun assembly into the wellbore, the autonomous perforating gun comprising;
a perforating gun;
a depth sensor for sensing the location of the perforating gun within the wellbore based on the spacing of casing collars along the wellbore; and
an on-board controller configured to send an actuation signal to the perforating gun to cause one or more detonators to fire when the locator has recognized a selected location of the perforating gun along the wellbore; and
autonomously firing the perforating gun along the first zone of interest;
injecting a slurry into the wellbore perforation at a first injection pressure that is below a screen-out pressure, the slurry comprising a fracturing proppant;
continuing injecting the slurry into the wellbore perforation at the first injection pressure and until the first injection pressure increases to a second injection pressure that is greater than the screen-out pressure, wherein the second injection pressure is sufficient to release and unsecure the valve to move the valve from the closed position to the open position and expose ports along the production casing to the subsurface formation at or below the valve; and
further pumping the slurry through the exposed ports, thereby averting the occurrence of a screen-out condition.

12. A system, comprising:
an oxygen sensor adaptor housing configured to mount in at least one of a combustor section of a gas turbine engine, a turbine
section of the gas turbine engine, or an exhaust section of the gas turbine engine, or any combination thereof, wherein the
oxygen sensor adaptor housing comprises a coolant inlet configured to receive a coolant into the oxygen sensor adaptor housing,
and a coolant outlet configured to convey the coolant away from the oxygen sensor adaptor housing; and

an oxygen sensor disposed in the oxygen sensor adaptor housing, wherein the oxygen sensor adaptor housing is configured to
convey the coolant through an interior of the oxygen sensor adaptor housing to maintain a temperature of a portion of the
oxygen sensor below an upper threshold.

1. A seismic vibrator comprising:
an actuator comprising two oppositely rotating, adjustably eccentric masses;
a motor that powers the actuator, and controls a rotation frequency of the eccentric masses;
an eccentricity adjustment system that changes eccentricity while the actuator is operating, whether or not the rotation frequency
is simultaneously being changed, and independent of any change in rotational frequency; and

a sweep controller that controls the motor and the eccentricity adjustment system to provide a combination of eccentricity
and frequency required to produce an output proportional in magnitude to, and in phase with, a pre-selected sweep input signal.

1. A method for protecting a metal surface within a flow system from corrosion, comprising
providing sacrificial anodic particles;
injecting the sacrificial anodic particles into a fluid stream within an injection manifold;
protecting the metal surface from corrosion through a reaction between the sacrificial anodic particles and the metal surface;
separating the sacrificial anodic particles from the fluid stream;
recycling the sacrificial anodic particles that have been separated from the fluid stream and that are reusable; and
re-injecting the recycled and reusable sacrificial anodic particles into the fluid stream.

1. A storage container, comprising:
a support frame fixedly attached directly to at least one top panel, at least one bottom assembly, and a plurality of corrugated
side panels having corrugations, wherein the support frame is externally disposed around the storage container;

wherein an interior surface of the at least one top panel, at least one bottom assembly, and plurality of side panels is an
interior surface of the storage container and an exterior surface of the at least one top panel, at least one bottom assembly,
and plurality of side panels is an exterior surface of the storage container;

wherein the support frame is configured to operably engage at least a portion of a hull of a marine vessel; and
wherein the storage container is an enclosed, liquid-tight, self-supporting storage container capable of transporting liquefied
gas.

1. A computer-implemented method for automated rock physics modeling, comprising:(a) pre-processing log data obtained from a suite of logging tools and corresponding auxiliary information over a range of depth of a subterranean formation, the pre-processing including;
(i) dividing the log data and the corresponding auxiliary information into zones within the range of depth,
(ii) coarsening the log data and the corresponding auxiliary information by determining an average value for the log data and the corresponding auxiliary information for each zone to produce a coarsened log data and a coarsened corresponding auxiliary information over the range of depth;
(b) solving an inverse problem associated with the rock physics model with a method comprising,
(i) identifying a list of parameters associated with the range of depth within the subterranean formation,
(ii) dividing the list of parameters into a set of at least two subgroups of parameters,
(iii) perform a local inversion for each of the at least two subgroups of parameters identified in step (b)(ii) to obtain optimum values for all parameters belonging to a given subgroup,
(iv) collect the optimal values of parameters obtained in step (iii) to determine the optimal values for the list of parameters identified in step (b)(i) by comparing the local inversions from step (b)(iii) with the pre-processed log data from step (a) to identify the subgroup of parameters as the optimum set of parameters for use in a forward run of the rock physics model; and
(c) computing a set of rock mechanical properties, comprising
(i) a forward run of the rock physics model using the optimal parameters obtained in step (b)(iv) to calculate at least one of density log, a compressional velocity log and a shear velocity log,
(ii) calculating an optimized set of rock mechanical properties for the range of depth use the at least one of the calculated density, compressional velocity and shear velocity logs of step (c)(i) in a rock physics model.

17. A system, comprising:
a turbine combustor, comprising:
a head end portion having a head end chamber;
a combustion portion having a combustion chamber disposed downstream from the head end chamber, wherein the combustion portion
comprises a combustion liner radially disposed about the combustion chamber;

a cap disposed between the head end chamber and the combustion chamber;
a flow sleeve disposed about the combustion liner, wherein the flow sleeve is configured to direct a first exhaust flow toward
the head end chamber between the flow sleeve and the combustion liner;

a flow separator directly coupled to the flow sleeve upstream of the cap in the head end portion of the turbine combustor,
wherein the system is configured to split an exhaust flow into the first exhaust flow and a second exhaust flow, the flow
separator is configured to separate the first exhaust flow from an oxidant flow, and the flow separator is configured to direct
the first exhaust flow into the head end chamber;

at least one exhaust extraction port directly coupled to the head end portion of the turbine combustor, wherein the at least
one exhaust extraction port is configured to extract the second exhaust flow from the turbine combustor; and

a mixing region configured to mix the first exhaust flow with the oxidant flow to provide an oxidant-exhaust mixture.

1. A mooring system for a floating vessel, the floating vessel having a platform for conducting operations in a marine environment,
and a floating tower for providing ballast and stability below a water line in the marine environment, the floating tower
being constructed and arranged to detachably connect to the floating vessel, the mooring system comprising:
a plurality of anchors disposed around the tower along a seabed;
a plurality of primary mooring lines, each primary mooring line having a first end connected to the tower proximate to a top
end of the tower and a second end operatively connected to a respective anchor; and

a plurality of secondary mooring lines, each secondary mooring line having a first end connected to the tower proximate a
bottom end of the tower and a second end connected to a respective anchor.

1. A computer-implemented method for ensuring stability of iterative inversion of seismic data to infer a model of at least
one physical property of a subsurface region, wherein a model update is computed, using a programmed computer, for a next
iteration by optimizing an objective function measuring misfit between the seismic data and model-simulated seismic data,
said method comprising:
using the computer, determining when a model update will cause an unstable simulation, and in response to such a determination,
using a Projection Onto Convex Sets to find a nearest stable model; and

using a final model from the iterative inversion for geophysical prospecting,
wherein the optimizing of the objective function comprises performing a line search in model space in a direction indicated
by a gradient of the objective function, and

wherein the stability projection operator P is applied before beginning the line search, the line search determining an update
for each model parameter m from the ith iteration to the i+1 iteration using a relationship that can be expressed as

mn+1=mn+?(P[mn+?sn]?mn)

with the search being on ?, 0

1. A computer-implemented method for obtaining a time-based model of data describing a physical structure associated with
a subsurface region, the method comprising:
obtaining a set of time instance objects from a domain object, wherein the domain object encapsulates a physical description
of the physical structure and the set of time instance objects encapsulates a time dependent description of the physical structure
associated with the subsurface region at given times, wherein each time instance object is associated with a given time;

obtaining data describing the physical structure and time interval data related to the physical structure from each member
of the set of time instance objects;

obtaining dependent data that is associated with the data describing the physical structure in the model of data describing
the physical structure, wherein the dependent data has associated time interval data, the time interval data associated with
the dependent data has a finer time granularity than the time interval data related to the physical structure, wherein a plurality
of time interval data associated with the dependent data is associated with each time instance object;

creating, using a computer, a time-based model of the data describing the physical structure in conjunction with the time
interval data; and

automatically synchronizing at least one member from the set of time instance objects with an associated dependent data to
facilitate viewing production information across the physical structure at the given time using the time-based model.

1. An integrated system comprising:
a gas turbine system comprising a combustion chamber configured to combust one or more oxidants and one or more fuels in the
presence of a compressed recycle stream, wherein the combustion chamber directs a first discharge stream to an expander to
generate a gaseous exhaust stream and at least partially drive a main compressor, wherein the one or more oxidants and the
one or more fuels are separately provided to the combustion chamber so as to be in a stoichiometric ratio of between 0.9:1
and 1.1:1 in the combustion chamber; and

an exhaust gas recirculation system, wherein the main compressor compresses the gaseous exhaust stream and thereby generates
the compressed recycle stream;

wherein the exhaust gas recirculation system comprises (i) at least one cooling unit configured to receive and cool the gaseous
exhaust stream, (ii) at least one blower configured to receive and increase the pressure of the gaseous exhaust stream before
directing a cooled recycle gas to the main compressor, (iii) a second cooling unit configured to receive the gaseous exhaust
stream from the at least one blower and to adjust a temperature and lower a dew point of the gaseous exhaust stream to the
main compressor thereby generating the cooled recycle gas, and (iv) a feed/effluent cross exchanger in series with the second
cooling unit configured to adjust the temperature of the cooled recycle gas to achieve a dew point margin of

at least about 20° F.

1. A mooring system for a marine vessel comprising:
at least one mooring line, the at least one mooring line having a first line section and a second line section; and
an extension device, the extension device comprises:
a first component, the first component attached to the first line section and having a first shear pin hole,
a second component, the second component attached to the second line section and having a second shear pin hole,
a shear pin positioned within the first shear pin hole and the second shear pin hole thereby connecting the first component
and the second component, and

an extension line having a first end connected to the first component and a second end connected to the second component.

1. A method of producing hydrocarbons comprising:utilizing a vector volume to determine the location of hydrocarbons, wherein the vector volume is created by:
a) obtaining measurement data in a data volume associated with a subsurface region;
b) computing initial vector estimates for the data volume to form a vector volume;
c) flattening at least a portion of the data volume based on the vector volume;
d) computing an error estimate based on the flattened at least a portion of the data volume for each sample;
e) determining whether the error estimate is within a threshold;
f) updating the initial vector estimates in the vector volume based on the computed error estimate, in response to the threshold not being satisfied; and
g) one or more of storing the vector volume in memory accessible by a computer system and displaying the vector volume on a display accessible by a computer system, in response to the threshold being satisfied;
h) drilling a well to access the hydrocarbons based at least in part on the vector volume; and
i) producing the hydrocarbons from the well.

13. A power generation system comprising:
a first compressor configured to receive and compress one or more oxidants to generate a compressed oxidant;
a first combustion chamber configured to receive and substantially stoichiometrically combust a first portion of the compressed
oxidant, at least one first fuel, and a first diluent to generate a first exhaust stream;

a first expander configured to receive the first exhaust stream from the first combustion chamber and generate a first gaseous
exhaust stream;

one or more sensors used to measure one or more components of the first gaseous exhaust stream;
a metering valve configured to be adjusted to control a flow of the first portion of the compressed oxidant into the first
combustion chamber based on one or more measurements from the one or more sensors in order to maintain substantially stoichiometric
combustion conditions in the first combustion chamber, wherein substantially stoichiometric combustion is a combustion reaction
having an equivalence ratio in a range of 0.9:1 to 1.1:1;

a second compressor configured to receive and compress a cooled recycle stream to generate a compressed recycle stream;
a second combustion chamber configured to receive and combust a second portion of the compressed oxidant, at least one second
fuel, and a second diluent to generate a second exhaust stream;

a second expander configured to receive the second exhaust stream from the second combustion chamber and generate a second
gaseous exhaust stream;

a heat recovery steam generator configured to receive and cool the first and second gaseous exhaust streams to generate a
combined exhaust stream and steam;

a cooling unit configured to receive and cool the combined exhaust stream and generate the cooled recycle stream; and
a separator configured to receive and separate a first portion of the compressed recycle stream into a separator effluent
stream primarily comprising carbon dioxide and a separator product stream primarily comprising at least one of nitrogen, oxygen,
and argon;

wherein the compressed recycle stream is split into the first portion and a second portion upstream of the separator, the
first diluent comprises a first portion of the separator product stream, and the second diluent comprises at least a portion
of the second portion of the compressed recycle stream.

1. A method for completing a well in a reservoir, comprising:
injecting a stimulation fluid to stimulate a first interval in the reservoir, wherein the stimulation fluid is at a pressure
sufficient to open a plurality of check valves in the first interval, allowing stimulation fluid to flow into the first interval;

dropping a plurality of ball sealers into the well to stop a flow of the stimulation fluid into the first interval and begin
treatment of a second interval, wherein the ball sealers are configured to block flow through the plurality of check valves
in the first interval;

injecting the stimulation fluid to stimulate a subsequent interval in the reservoir, wherein the stimulation fluid is at a
pressure sufficient to open a plurality of check valves in the subsequent interval, allowing stimulation fluid to flow into
the subsequent interval; and

repeating the dropping of ball sealers until all intervals are treated.