Current oil production technology is qualitative
and pragmatic, relying as it does on the accumulated experience
base of geological/engineering teams managing each asset using
seismic surveys, logging, and production histories, integrated
into two-dimensional (2D) maps and graphs (even when 3-D seismic
surveys are used to make the maps). State-of-the-art quantitative
methods, which visualize the data in three dimensional (3D)volumes,
are now coming into wide acceptance in the offshore, and increasingly,
the onshore as well. Significant improvement production have
been documented when migrating from 2D to 3D technology; and success
rates in finding oil and gas based upon 3D interpretations have
been documented by the majors to increase from <15% to >35%
of wells drilled.
The next-generation production technology which we
term 4D reservoir monitoring, (i) visualizes an integrated, 3D
volume of datasets from at least four disciplines (geophysical,
geological, geochemical, and reservoir engineering) from a field
merged into 4D (x, y, z, and time-lapse), and (ii) interacts with
finite-element models of the fluid-flow (drainage) history required
to reproduce these observations. The fourth (time-lapse) dimension
accompanied by modeling enables an understanding of the nonlinear
fluid flow of hydrocarbons from reservoir rock into the producing
wells. Improved production management is the result.
In the future, monitoring programs will be specially
designed to expand to real-time monitoring and control, which
we term 5D will integrate additional data sets, compiled by next-generation
geophysical monitoring tools such as permanently installed acoustic
sensor arrays, borehole source/receiver arrays, gravity gradiometers,
and in situ flow detectors. The fifth dimensional technologies
consider time in two senses: more advanced analysis and modeling
of historical data from the past (a true simulation environment),
and more advanced delivery of sensor information in real-time
to compare with the simulation results.
The new 4D and 5D technology "paradigm shift" will create real physical value (more oil is extracted from old fields); this real value translates to increased cash flow. In addition, this new technology will avoid production problems (like water incursions and unexpected gas cap formation), again increasing both the cash flow and asset value. Technology which generates lower production costs is the key to success in managing the effects of short-term and long-term oil pricing dynamics.
Geophysical
Certainty in NPV Calculations
Oil and gas decline curves can be predicted from
current "best-practices" within reasonable (10%) accuracy
once extraction begins. This production-versus-time curve follows
a log-log distribution(that is, it is FRACTAL). Initial production
increases rapidly to a maximum and then declines in a predictable
manner for each field. Good technological companies can minimize
the decline rate in each field and produce a smaller Fractal constant
(slope of the decline curve in log-log plot. 4D production
management technologies hold the possibility of increasing flow
rates and shortening extraction times to improve fractal statistics
of each field, and in many cases improve from the fractal assumption
altogether.
Oil companies have several fundamental needs: (1)
to lower their costs of exploring for, discovering, appraising,
and developing new hydrocarbon reserves in an economic manner
(to increase their competitiveness and profitability); (2) to
manage their exploration and production risks; (3) to reduce
exposure to price fluctuations (in the short term, this is done
with forwards, futures, options, and swaps, in the long term it
is achieved with lower costs); (4) to replenish their reserves,
and (5) to optimally utilize oil-rich assets (that is, extract
as much oil as possible by increasing success yields in new drill
sites, and maximize oil flow rates from existing sites).
In a tangible sense, oil companies face many exploration
and production problems which negatively impact their costs and
increase their risks. Universially, the technologies that they
currently use (from 2D in small companies progressively to 3D
in the largest companies) allows them to discover these problems
only after they occur, so that a huge amount of valuable resources
are expended in a reaction mode to contain problems as
best as they can. With 4D technology, many technical and operational
problems encountered on the field can be predicted in advance
(and therefore proactively minimized or completely avoided) (e.g.,
decide to drill a well to remediatw water incursion before it
happens).
4D is advanced
3D seismic imaging done many times over the same volume, and then
integrated with other domains of information (e.g., pressure,
acoustic and temperature monitoring from inside producing wells,
legacy information from past performance of the field). 4D
thus enables very accurate measurement of
nonlinear changes in the reflectivity, pressure, temperature,
and produceability of the rock and fluids (oil, gas and water),
the mapping of drainage, and the imaging of bypassed oil and gas
from within the volume. Corrective wells can then be added to
drain missed hydrocarbons.
4D is the next-generation technology after today's
state-of-the art 3D technology. Although 3D has radically increased
exploration success and production volumes, it is implemented
on a limited basis (We estimate that 3D is utilized in fewer
than 2% of all oil fields.) 4D4
thus represents a double leapfrogging of technology in
the preponderance of cases. Our analysis suggests that 4D4
technology will increase the success rate in finding oil to 60%
(since 45% of all E&P expenses are drilling, the costs will
be enormously reduced per barrel of oil now booked as "proved"),
while concurrently increasing the flow rate of existing wells
by over 20%. The computational and networking infrastructure of
a 4D4 control environment for oil and gas production will enable
a much-needed and radically-new, information-rich approach to
the exploration and production of oil and gas. The realization
of an intelligent Field Controller can be realized for every
field THC owns--lowering the recovery costs of each barrel company-wide.
With smart production practices involving 4D4
technologies, THC can make underperforming fields compete with
the National Oil companies such as Saudi Aramco--at extraction
costs of $2/bbl.
We envision the oil and gas company of the future to have integrated, computationally rigorous, control centers for all reservoirs in all fields. These simulation and control centers will be constantly updated and recomputed to react to new sensor data coming in from 4D4 surveillance of the field and from instrumented boreholes and wells that contain pressure, temperature, and acoustic transducers that detect changes in production activity in the field--IN REAL TIME. The simulators are parallelized 3-D, FEM's of two types--acoustic and elastic forward and inverse models that interpret the seismic changes in the field, and reservoir flow simulators that predict the flow of oil, gas, and water throughout the field. The models and datasets reside on distributed computational resources in multiple locations, and both the data and computational cycles are accessed remotely, and invisibly, by the \control operator, who sees and interacts through a new generation of 3-D holographic visualizer which we are also developing (SpaceGraph). The mission control operator calls up windows that display not only the models and datasets, but the differences and similarities among them to maximize production efficiency in the field.
The wellheads and wellbores in a technologically controlled field will be instrumented and connected to a network so that production data can be remotely acquired -- even to minute timescales. Currently this is a manual process with collection intervals of days. Well heads would incorporate remotely controlled chokes and valving to provide a basic set of effectors. This might require some new wellhead hardware, and it is anticipated that subventures would be formed to produce, acquire, or adapt the necessary monitoring technology. For example, Lamont has a patent for a temperature string to implace in well casing, but the prototype has never been installed in a well.
The current state of the technology for the control
of the extraction process is qualitative, often relying on the
accumulated experience base of engineering teams, and is essentially
pragmatic. A more quantitative approach is clearly desired, but
the development of such has been impeded by several technical
factors in addition to conservative management practices:
1) The analysis and computation activities in oil and gas
production cover several interacting scales of interest. They require
communication between large-scale fluid flow models and small-scale, high-resolution reservoir simulation models that can match the resolution of individual well logs and well production histories. Similarly, seismic processors and interpreters must collaborate more in the correct visualization of subsurface reservoirs. Within the industry, each scale is treated by different specialists -- often in different organizations and with different heritages of faith in computer modeling and analysis. The interactions among the scales, driven often by organizational boundaries, have been consistently
information-poor.
2) The computing power necessary to quantitatively couple the
seismic scale to the reservoir scale is just becoming available. We
are just beginning to assemble a suite of analytical
and modeling tools across several organizations that cover all
the scales necessary to integrate seismic and well-log data for
information-rich and on-time production control. Specifically,
the partners in this proposal now have in hand 4D4 seismic interpreters,
3-D acoustic and elastic seismic models, parallelized 3-D reservoir
simulators, and intensely monitored demonstration fields that
have seismic as well as production histories from throughout the
lives of the fields.
3) Once a quantitative approach to Field Control
is created, the challenge remains of enabling the disparate software
components to interoperate in a distributed-but-secure way across
collaborating organizations. We must produce a major new network
protocol layer we call the "orchestration layer", to
steer and manage the distributed collaborative computation needed
for the Field Control concept.
4D4 can be
implemented today through the integration of off-the-shelf
hardware with state-of-the-art technologists. Current wellhead
sensors exist (for pressure, temperature, and gas/oil/water mix),
as do remotely-controlled chokes. Since telemetry technologies
are standard, the instrumenting of the wellheads can be performed
very quickly. In addition, bypassed pay can be immediately identified
with reshooting of existing fields with new 3D seismic surveys
under the 4D4 technologies umbrella.
(II) What are 5Dn technologies and how do
we get there?
5Dn Technologies consist of the real-time analysis
of multiple datasets -- the product of both monitoring and forward
modeling -- being collaboratively fused, visualized and realized.
Data is routinely collected in real-time over packet-switched
communication links by sensor networks placed in all wells within
production fields. Computation is distributed across a high speed
information infrastructure -- all steered at the visualization
and realization nexus by controlling personnel.
The most influential force that affects the computer
processing methodology behind 5Dn oil and gas production is that
drainage monitoring and remediation is an ill-posed inverse problem.
The 5Dn mision is to build a simulator of what is happening "down
there" at all spatial and time scales of interest including,
seismic, well-logs, prior knowledge of geological structure and
process, etc. Control of well production, guided by such models,
is like a multi-arm Shiva with information gathering and control
arms working at different time and spatial scales. The challenge
is in both the instrumentation of the field (seafloor seismic
sensors for example) and modeling (high resolution seismic models
that can match well logs AND surface seismic images). The 4D4
and 5Dn goals are to progressively couple today's seismic scale
to tomorrow's reservoir scale. Below is a brief description of
the steps involved in attaining such an information rich technological
environment:
Analysis Combined with Forward Models and Data
Fusion
The solution to the inverse problem involves the
combination of going backwards from data to inferred possible
models and then to evaluate and eliminate drilling candidates
by running them in a forward direction. Since ill posed inverse
problems have many feasible forward models, prior and external
knowledge of the problem helps constrain the possible models.
In a nutshell, the tracking of changes in multiple data sets
in time will be used to complete the "drainage" picture.
The integration of these diverse datasets can be thought of as
a data fusion process.
Interactive Visualization & Realization
A further need for realizing 5Dn production control
is the visualization of the multiple variables of the integrated
3D datasets -- that is to understand what the acoustic images
mean in terms of rock,oil and gas properties. This must be accomplished
though large scale modeling of the data on computers. The future
interactive visualization of seismic data will be coupled in real
time with realization -- one will be able to "steer"
the models and "drill" hundreds of synthetic wells before
a real well is placed in the ground. The oil industry is in the
"wind-tunnel" days of the aerospace industry. This will
be accomplished by coordinating distributed modeling and analysis
over the national information infrastructure with visualization
stations as critical focal points along the interpretatoin tunnel.
Field Control
The challenge is to provide information-rich control for fields in
production. We want to be able to track and model
oil-water-gas contact boundaries and to estimate rates and capacities
of the reservoirs. With this information better real time control
of the field can be enabled. In the further exploitation of fields,
the detailed information of drainage can be used in directional
drilling and completion of horizontal wells.
Drilling - a Critical Component
In the midst of all this computing,
the fact remains that drilling is the ultimate proof-of-concept
and discovery mechanism in oil and gas production. Wells are the
advanced guard technological proving grounds, much as wind-tunnels
were in the pre-computational Aerospace industry. Guidance to
and feedback from wells are indeed a product of and a valuable
resource to the seismic and reservoir modeling and analysis within
the mission control environment. In addition, they represent
fully 45% of E&P expendatures, and so must be modernized.
B. The 5D Technologies
1. Component-Based Software and Agents
The information-infrastucture change requireed for
a company to convert to 4D4 and 5Dn technologies is enormous and
profound. It implies a large change in the way computer products
interact across organizations and disciplines in the Oil and Gas
business. We will be required to do enterprise re-engineering
of all computer-aided science and engineering aspects of the acquireed
companies. The problem begins at the wellsite where we would
integrate and install a commercially available array of sensors
to detect temperature, pressure, fluid fluxes, oil/gas/water mixes
and vicosity changes. The sensors have been invented (some by
Lamont), but never intergrated into what we call a "Smart
Wells" configuration. The information must then be transported
in near-real-time to the control center, merged and interpreted
by the interpretation team using "component-based software"
introduced with the sensor arrays (a BBN specialty). Intellegent
agents must also be introduced to move software components to
the distributed database because the data sizes are often too
large for transport. Agents also act as projectors which extract
only the components of the datasets of immediate interest.
2. Orchestration
A new orchestration layer must be be developed that
can act intelligently to interoperate among the varying demands
of the applications within the Field controller. This layer will
exploit lower level networking capabilities to more efficiently
implement interoperations than coordination language environments
alone. Not allowing the lower network layers to help deliver
high level service requirements of applications in an informed
way makes it impossible to cope with the interoperating demands
present in future oil and gas production computation. In fact,
the temporal and spatial scales of these demands reflect the temporal
and spatial structure of the domain. The orchestration layer will
translate domain-specific high-level interoperating demands to
lower-level service requirements. It manages and optimizes in
order to corral lower-level layer functionality to meet these
constraints. Persistence, not just for buffering, but for checkpoint-restart,
interrupt, and redirection functions will be necessary.
3. Visualization
We require the development of novel 3-D visualization technologies and software modules (controllers), and networked, on- and off-platform seismic processing, modeling and integration software modules (with remote packet switching to deal with the computing communications needs). The technology involves the development of true 4-D color imaging (BBN's Color Spacegraph and other Virtual Reality ways of interacting (using probes) with the controller. The probes will be intelligent -- some will have pattern recognition capability to assist with quantitative questions such as volumetric improvements, Gas/Oil/Water mixes, etc.
4. 4D Seismic Interpretation Technologies
The development of quick-look 4-D seismic analysis
modules is one of the major drives of the project. The critical
requirement is to deliver modular software that allow solutions
to time dependent observations in time for production decisions.
That is, realistic Production Time-Scales must drive our ability
to visualize 4-D seismic data and its integration with other geological
information and seismic/reservoir models. The goal is to take
production engineering out of the 2-1/2Dworld (2-D bounding horizons
plus production logs in time) into a true 4-D world of observing
the remaining volume and volume change of a producing reservoir
over time. Where is the oil and gas coming from and when, within
the context of true intricacies in the drainage pattern? Another
goal is to allow for a more global reservoir picture than presently
available to production engineers. This involves the further development
of pattern recognition and tracking software to get quantitative
production predicitons out of the 4-D seismic datasets. These
will be the first products of the THC. Additional 4-D detection
technologies will then be developed such as time-dependent well
logging, and well sensor arrays that are cemented into the casing
during the initial stages of every new well--the 5Dn technoplogies.
5. Database management.
Database services for the Field Control Environment
must be distributed -- especially when considering the intellectual
property rights of the data product spectrum across collaborating
companies. Graded access levels will be needed. An object-oriented
representation of the combined schemas (i.e., a mixed approach
combining traditional relational with object oriented databases)
will make browsing the data appear seamless. We must develop
a GeoModel Server (GMS) to support uniform mechanisms for scalable
access to heterogeneous geological models. The GMS bears a functional
analogy to WWW servers, except the patterns of access and manipulation
of data that it must support are substantially richer and address
the special features of geo-models. We will build GMS as a generalization
of WWW servers. GeoModel Information Server (GMS) technologies
link related heterogeneous sources of geological information:
stored seismic models, on-line sensor information, and results
of running computations. GMS technologies generalize WWW to support
efficient access by computational agents. We will develop a Geo-Modeling
Language (GML), in analogy with HTML, to create a common representation
of geo-models and linkages between them. The GMS server will support
mechanisms to control and account for access, to permit organizations
to leverage their geo-model resources for commercial benefits.
GMS servers will organize computational access to distributed
stores of geological models as well as sources of real-time measurements
The GMS architecture generalizes WWW in several ways. First, we
generalize from documents to a mix of stored and computed geological
information. Second, we generalize the retrieval of documents
via URLs to launch computational agents. Third, navigation and
execution of geo-model computations is controlled by agents rather
than by an end user. Fourth, we must develop mechanisms to identify
ownership by controlling authorizations of agents and accounting
for their usage. These generalizations should be valuable for
large scale sharing of complex information resources in other
fields, as well.
6. Integrator
The THC will utilize multiple 3-D Seismic Datasets (4-D), including ongoing seismic reservoir monitoring, to control production through a modular reservoir controller. The controller connects modules that give the production engineering team the capabilities of calculating the optimal extraction strategy for each reservoir in an oil field. Modules for acoustic and elastic seismic models will be linked to 4-D seismic data analysis modules and reservoir simulation modules in order to computationally control production in an oil field--for the first time ever. Models and datasets will be jointly visualized and interactively compared utilizing component-based software. The development of the 4-D nexus between seismic data analysis and
forward models of the different species -- reservoir,
elastic, acoustic will allow for interaction and "data fusion"
among the production engineer, geologist and geophysicist. People
will be able to explore and interact with the volume in an interactive,
unimpeded, and intimate way.
Note that the current information model is based
on geologists' mental models which are built over years of experience.
The software will encapsulate this knowledge and "learn"
over time with experience. THC will build an ever-increasing
electronic knowledge base of how the earth operates, and with
this knowledge we will achieve even higher yields. We will be
continually increasing the long term value of THC's assets. Recall
that 2D and now 3D information are considered priceless, guarded
assets of oil companies because they show more information about
the value of the asset; 4D and 5D will be even more valuable
because more and better information will be embedded in them.
General: The technologies of the future oil field will change the ecconomics of production fundamentally. we seek an independent evaluation of the worth of both new fits of 4D4 technologies to future fields (A generic example IS GIVEN IN APPENDIX 17), but also of retrofits to existing production. Building on evaluations conducted by Exxon, Amoco, Shell and Arthur Anderson on the benefits of 3D to exploitation of known fields (APPENDIX 18), we can define a set of assumptions and questions to be answered by the independent appraiser of this business plan. Based upon the Amoco and Exxon evaluations, an improvement in overall economics of a field retrofit with 4D4 technologies should be 50% above what is simulated for the future of the field if 3D is already present, and 35% if no 3D currently exists over the field. INSTALLATION AND ACQUISITION COSTS OF THE NEW 4D4 TECHNOLOGIES ARE NOT ACCOUNTED FOR IN THESE COMPUTIATIONS. SEE TASKS BELOW FOR COST ESTIMATES.
>
> 1. Changing Financial Assumptions of the future oil patch
>
a. 4D4 rather than 3D. Amoco found that 3D in a production environemnt improves initial production rates, adds drilling targets and optimizes facilities for the size of expected production-- if available before exploitation begins. They found that the average improvement in revenue generated was 35% for 3D over 2D--from two sources, added drilling locations and saved dry holes. Amoco found that new well locations provided a 12% success rate improvement, and production/well DOUBLED. 4D4 can be expected to do 50% better than 3d alone, since it employs the same technologies recorded repeatedly during the life of a field. However, they found that 3D alone was unable to distinguish bypassed pay after production began in any given well--a strength of 4D4. Exxon found that even including the added cost of acquiring 3D over 2D, two strong market forces drove 3D to impressive cost-effectiveness. First, added value profit (AVP) from recovered hydrocarbons that would have been simply missed was high, and second, investment savings from fewer dry holes and misplaced surface installations was alsost as impressive. For example, Exxon found a 27% drilling success rate improvement. Total financial return was increased 22% in the Gulf of Mexico and 33% in Indonesia. 4D4 should produce a 15% improvement on these 3D because repeated ensonification and monitoring will essentially "REAPPLY 3D THROUGHOUT THE LIFE OF A FIELD" resulting in the recovery of more "probable" reserves.
b. Slope change in depletion curve. Amoco found
that the expected decline curve was reduced from 25%/yr to 12%/year
of these locations. The decline was still exponential (Fractal)
because nothing was done after emplacementation of the wells.
4D4 monitors the hydrodynamics of the wells throughout their
lifetime. The Fractal, or exponential decline curve used for
normal evaluations must be changed to assume that 4D4 changes
the dynamics of drainage to be mroe like the generic scenerio
description.
d. Changes in discount rate. Amoco found that the discount rate was improved because delays in implacing deliniation wells and facilities were eliminated. 4D4 should cut the discount rate from 10% to 8%.
B. Technical Challenges
to be Overcome
2) Our understanding of 4-D seismic data requires
the juxtaposition of analyses of seismic data and modeling of
seismic and fluid flow results over short time frames (i.e. years).
None of these huge datasets have been integrated into a single,
modular controller before. This nexus of analyses of real data
and models of several species of geologic structures is just now
attracting interest throughout the industry, but the scale of
our synthesis and vision is completely unique.
3) The network-based inter-operations of several geodynamic models with the results of 4-D seismic analysis pose unique computational challenges. We envisage the development of an architecture for "lego" models. These models will be able to describe themselves to each other, and an interface layer will be able to adapt to a mutually specified set of needs such as spatial and temporal resolution (auto re-gridding). This will involve the development of network based protocols and a new orchestration protocol layers that can a) understand the requirements of the models such as variable mesh geometries among seismic vs reservoir simulators vs fluid flow models, and b) provide
interpolation and unit conversion services between
the models. This alone is a unique challenge for our THC. Providing
theconcert function as a network service can lead to profound
data exchange bandwidth efficiencies. Providing semantic descriptions
of the Component-Based modules to the orchestration layer can
also allow this layer to migrate modules among different hardware
to load balance, as well as provide security within the project.
Cost, computer cycle and communications effectiveness will result
from the orders-of-magnitude improvement in the scientific understanding
of how fluids drain into wellbores in the subsurface over time.
4) The appropriateness of technical risk and feasibility
of our required nexus between simulation and data analysis cannot
be overstated for the exploitation of our reservoir controller.
One of the challenges for the nexus is the proper technology to
visualize and interact with all the data -- empirical and model
results. All virtual reality attempts at grand-challenge visualizations
have failed in our view. We believe that a critical component
leading to project success will be the development of a true 3-D
volummetric interactive display form for the geophysicist, geologist
and production engineer to place their interactive hands and minds
into. Interaction with this volume will allow feedback to the
4-D software modules that are responsible for drainage analysis
and data modeling. The data/model interactions are too complex
to be comprehended and controlled by humans (let alone machines)
without this "virtual reality--minus the restrictive headgear"
frontend. This is the key to getting our technological advances
out into the field and used!
This "Field Controller"
technology will make use of vastly more and diverse kinds of data
and models than ever before attempted to completely characterize
subsurface fluid extraction. Models will simulate flow with the
same resolution as subsurface acoustic mapping so that the acoustic,
thermal and pressure consequences of extraction can be accurately
maximized. Flow simulations will become part of the database
in a reservoir, preserving a record of past interpretations and
building an experience base for future application to similar
reservoirs worldwide.
The volume of data needed to describe
the subsurface and the extraction of fluids from the earth are
very large. The datasets resulting from multiple 3-D seismic
surveys that form the foundation of our volumetric, time-dependent
4-D imaging are new (e.g., the 3-D processing is itself a recent
technological development) and are just now becoming widely enough
available to b of tremendous interest to subsurface fluid extraction
industries. Three dimensional datasets with resolutions of less
than 40 m are now routinely acquired over areas that are hundreds
of kilometers in surface dimension. Virtually the entire offshore
Louisiana south additions has been imaged by 3-D seismic profiling
--three distinct times by Shell Oil Company alone. In addition,
seismic processing involves some of the largest computational
manipulations in the world, e.g., large and diverse data volumes,
computational densities, CPU efficiencies, days of CPU time to
complete, and Input/Output requirements.
The dataset from the processed interpretation
of a single 3-D seismic survey of a 20 km x 20 km x 6 km volume
exceeds 500 gigabits. Interpreting differences among several such
datasets in terms of acoustic changes related to fluid extraction
is difficult in part because it is not easy at present to overlay
datasets of such sizes. Some of the other datasets utilized are
also very large (modern imaging-based well logs and 3-D FEM modeling
simulation runs), some are small (such as geochemical data and
2-D seismic profiles), but a primary problem is that the different
data types reside on diverse machines, at diverse sites, in diverse
data base structures, and all must be integrated in order to produce
an accurate mission controller.
The Generic Oil Field of the Future Scenerio--the advantages of
4D4 real-time monitoring
General: When considering the list of production
troubles and ways 4d4 can make immediate improvements, it is useful
to consider the production history of a generic field. Value
can then be estimated for specific events that 4D4 cause to occur
when not othrwise, or at earlier times, etc. The below generic
example has been distilled from the productio histories of four
major plays in the southwestern United states. They are expected
to be applicable to international basins because all hydrocarbon
fields behave in a "fractal" way. That is, only the
constants of 1. maximum initial production and 2. the log/log
slope of decay of production over time need to be defined to characterize
produciton from oil and gas fields. Thsi methodology has been
developed by the USGS to project future reserves of the nation--a
task required of them by congress. THE FUNDAMENTAL ASSUMPTION
OF THE USGS METHODOLOGY IS THAT THE CONSTANTS DO NOT CHANGE BECAUSE
OF THE INVENTION OF NEW TECHNOLOGY (SPELLED OUT CLEARLY IN THEIR
1995 NATIONAL PETROLEUM ASSESSMENT). 4D4 TECHNOLOGIES CHANGE
NOT ONLY THE PEAK PRODUCTION AND SLOPE OF THE DECAY, BUT CAN CHANGE
THE SHAPE OF THE FALLOFF DECAY CURVE TO NON-LINEAR (NON-FRACTAL).
THIS WILL FUNDAMENTALLY CHANGE THE ECONOMICS OF OIL AND GAS FIELD
PRODUCTION.
Plays used:
> 1. Sandstone
> a. offshrore, young reservoirs
> Eugene Island 330, offshore La
> b. Onshore, old reservoirs
> McAllen Ranch, Tex
> 2. Carbonate
> a. fracture controlled permeabilty
> Austin chalk, Tex
> b. Porosity-derived permeability
> Cottonwood Creek
Arbuckle, Okla.
Generic Oil and Gas Field
1. Initial production. The production
plan for a modern oil and gas field is designed on a reservoir
simulator. The technology behind the simulator is rather simple:
a sparse grid is laid out in 3 dimensions covering the land position
and the subsurface reservoirs. Fluid flow control is along specific
well paths that are planned, and voxel information of permeability,
oil/gas/water mix, pressures, etc are extrapolated in between
based upon a geostatistical "kreiging" of some kind.
Flow is controlled by Darcy's Law (a linear pressure driver),
even in fractured formations. what little seismic information
entered into the simulator comes in the form of reservoir geometries
and thicknesses. Faults are also included, but their true pressure
isolation capabilities are only guessed at (by estimating the
amount of shale abutting the fault on either side). wells are
planned, and the pressure and fluid mix predicted over time.
it is routine for the simulation to be wrong by 50% at any given
time during the subsequent life of a field. Littel effort is
expended to update the simulation, and many, many old fields (pre-1985
or so) have no simulation doen at all. In such cases, the wells
were located entirely by structure (and the assumption that light
hydrocarbons flow "uphill".
Advantages of 4D4:
1. Our simulator is integrated with the seismic
volume from the beginning. we build in acoustic differences between
compartments, across sealing faults, between various fluid mixes.
The simulation is tested with "pre-drilling", or wells
placed to varify the model, then tested to establish the two prime
vasriables to profit: RATE-OF-FLOW, and VOLUMETRIC EXTENT OF
THE DRAINAGE.
Then a hydrodynamic model of drainage is computed
that places injectors at the proper places for maximum return
over the life of the field, and DELIVERS THE OIL AND GAS MUCH
MORE QUICKLY TO THE SURFACE THAN THE FRACTAL, NATURAL EARTH FLOW
MODELS ALLOW.
Consequently, we can place wells to maximize cash-flow
as well as recovery. In the generic example, not only is peak
production exceeded, but actual volumes produced run several years
ahead of conventional recovery technologies. IT IS IMPORTANT
TO NOTE THAT THE TECHNOLOGICALLY MOST-ADVANCED OIL COMPANIES DO
THIS TODAY. The 4D4 differeence is that with monitoring in real-time,
the simulation can be varified in weeks rather than in years required
for even those advanced companies.
For a generic example, consider a small field in
the deepwater Gulf of Mexico in which a conventional, water-driven
production plan is implemented with wells placed to structurally
drain oil and gas based upon updip flow assumptions. Say the drilling
was begin in 1991. It is assumed that the same amount of platform
expenses, total drilling and work-over efforts are expended for
the 4D4 and conventional histories of the field --so that drilling
costs are irrelevant--only placement and monitoring are different.
For the conventional field, installation of 12 wells
would produce peak production of 44,000 BOPD (barrels of oil per
day) and 90 MMCFPD (thousand mcf of gas per day), which would
occur in July, 1991 or so. Cash flow at maximum production would
be $880,000 for oil (assume $20/bbl) and $180,000 for gas (assume
$2/mcf). The field would then go into immediate decline and decrease
exponentially, with the exception of two workover program blips
until 100 MMBo and 180 BCF was produced by field shut-in in 2006.
For the 4D4 case, pre-drilling to validate the simulation/seismic
model would produce pre-production revenue from the extended flow
tests of $3.65 million from oil and $750,000 from gas during 1990.
Then 6 select, horizontal wells would be placed to maximize production
rates and volumes. Pressure is maintained with water injectors
drilled below the oil/water contact and gas injectors in the gas
cap. Peak production would be almost CONSTANT (+/- 5MBOPD) and
AVERAGE 60,000 BOPD and 100MMCFPD for the first three years of
the field's operations--no exponential decline in produciton.
50% "normal-technology" field depletion would be reached
at that point, when 60MMBO and 90 BCF would have been produced.
The revenue from that first three years would be $1.2 billion
from oil and $240 million from gas -- AND REALIZED THREE YEARS
BEFORE THE 50% POINT FOR THE CONVENTIONAL PRODUCTION PLAN.
Then, seismic and borehole monitoring detect that
one large fault block constituting 1/4 of the field's reserves
is suddenly cut off from existing wellbore drainage by a fault
that becomes a seal with declining pressure. That is, a compartment
containing 1/4 of the remaining reserves is not draining efficiently
in 1994, whereas it was 6 months before. A new horizontal well
is drilled into that compartment. The field is depleted rather
suddenly when the water and gas sweeps converge in 2001-2003 timeframe,
and the field is shut-in.
The combination of real-time monitoring of field
conditions matched to a reservoir-by-reservoir field simulation
of drainage that is constantly undated with information results
in the recovery of 650 bbl/ac-ft instead of the proved reserves
booking of 550 bbl/ac-ft. This addition of 20% is just about
equal to the proved plus possible reserves identified by the simulation
at the beginning of the field development. Additional income
from the 4D4 field management technologies is $480 million from
oil and $96 million from gas production--AND THE COST IS LOWER
BECAUSE FEWER TOTAL WELLS ARE DRILLED.
THE 1991-1995 HISTORY OF THIS GENERIC SCENERIO IS
FROM A REAL, STATE-OF-THE-ART SHELL FIELD. HOWEVER, IT IS NOT
BEING MONITORED AT THIS TIME. THE DIFFERENCE BETWEEN SHELL BEST-INDUSTRY-PRACTICES
AND 4D4 TECHNOLOGIES LAID ONTO THAT BEST-PRACTICE IS ESTIMATED
TO BE AN ADDITIONAL 10% RECOVERY FIVE YEARS FASTER.
Appendix 5: Total Value Proposition
This table is a summary of THC's total value proposition. It tabulates the total number of oil fields in the world by type (See Appendix XX for scenario types) to arrive at the total asset size. Then the assets are analyzed for their "availability" to be controlled by THC; for example, oil companies which are owned nationally are often not for sale at any price and thus cannot be considered in THC's available pool of potential acquisition targets. Next, the current net present value of the available assets is calculated in dollar terms, under the assumption that current technology is applied to their exploration and production. The fifth column records the net present value of these available fields if THC's enhanced 4D4 technology were applied. Finally, the difference between current value of available assets and 5Dn value of available assets is tallied in the last column, representing the total potential value that THC could generate.
| Type | Asset size
(# fields worldwide) | Worldwide assets potentially available to THC | Current value of available assets (in $US billions) | Value of available assets, with 4D4 technology | Increase in value |
| SY | |||||
| SO | |||||
| CF | |||||
| CP | |||||
Total |
Appendix 6: Market Concentration
Show graph with this information: Each subsequent
quintile of the total worldwide reserves is controlled by ten
times the number of companies which controlled the previous quintile
of reserves
| Total worldwide reserves | |||||
| Number of Companies |
The Advantages of 4D4 and 5Dn Real-time
Monitoring
A. Background
All oil reservoirs produce both gas and oil at the
same time. However, the gas/oil ratio (or GOR) varies widely,
depending on the well. For "oil wells", the GOR may
be only a few hundred mcf/bbl; for "wet gas wells"
that produce distillate (natural diesel), the GOR may be several
tens of thousands; and for "dry gas wells" that produce
virtually no liquids at all, the GOR is even larger. As we will
see below, this ratio is important to know, monitor, and control,
because the pressure dynamics indicated by the GOR have implications
for the extraction flow rates and the choice of production technique.
For example, by keeping the gas above the bubble-point (in solution)
within any given reservoir, the GOR can be controlled and recovery
can be improved.
To complicate matters further, water is a factor
in the pressure equation in addition to gas and oil. With time
and depletion, water is produced in all wells (even to some degree
in depletion drive reservoirs, see below). When the water-to-hydrocarbon
ration exceeds 95%, the well is closed ("shut-in") because
it becomes economically and operationally unviable.
Mixtures of any two phases (gas, oil, and water)
impedes the flow of any particular phase. The presence of three
phases has more impedance effect than two phases. Thus, the pressure
plan to ensure pressure maintenance is of utmost importance in
managing flow rates.
B. Universal improvements from 4D4
There are two main reservoir types: sandstone and
carbonate. All reservoirs-whether sand or carbonate-respond to
production in one of two ways depending on the hydrodynamic system
of the rock surrounding the reservoir:
1. Water-drive. If there is sufficient connectivity
to surrounding, water-filled rock, the opening of a pressure gradient
to the surface that produces oil and gas flow will produce a flow
of water to replace the oil and gas in the pore spaces of the
reservoir rock. This water-drive sustains pressures better than
the depletion-drive phenomenon (below), usually producing in a
better "sweep" of oil and gas. Thus the pressure depletion
curve is more gently sloped, and a reservoir will produce with
natural pressure drive for a longer period of time.
2. Depletion-drive. If the permeability
connection to surrounding rock is poor, then little water will
flow in to replace extracted oil and gas, and pressures will deplete
much more rapidly. Compaction and pore collapse are possible,
and oil and gas "sweep" is correspondingly reduced.
Some form of lifting of the reserves is required more quickly,
and the fall-off curve for production vs. time is generally steeper.
Advantages of 4D4
1. Which drive is present in a given reservoir is
often a surprise, with stacked reservoirs often alternating depending
on specific plumbing conditions within the rock. 4D4
will determine which much more quickly
than normal oil field practices, and remediation efforts can be
taken more quickly-for example, placement of new wells, or injection
of water to sustain pressures in a depletion-drive.
2. Also, during the history of production, often
rapid changes from one drive to the other can occur. 4D4
gives instant response to conditions such
as fault zone permeability barrier breakthroughs that can suddenly
inject water across faults. Also, water drive can deplete the
"reservoir" of available water, and new injection would
be required to maintain the water drive.
3. Also, a production plan often contains designed
injection of gas, or intentional formation of a gas cap to force
oil from distant edges of the reservoir to central production
wells. 4D4 gives real-time
monitoring of the success or failure of those injectors or gas
cap formation.
C. 4D4 benefits
specific to Sandstone Production
Rock Type: Oil and gas are produced almost completely from one of two kinds of rock: sandstone or carbonates such as limestone, dolomite or buried reefs. The slope of the fall-off in production over time is
generally controlled by the permeability of the reservoir, with carbonate permeability derived from either interconnected pores or from fractures, and the sand permeability controlled exclusively from pore
interconnectedness. However, there are production differences between the two types of reservoirs:
Problems in Sandstone Production
1. Sanding and clogged screens can plug the producing pipe
2. Water coning can force oil and gas away from the pipe
3. Gas cap pressure maintenance can fail dropping pressures to below that required to drive the oil and gas to the wellbore.
4. So/Sg/Sw mix must be monitored, but often is mixed from several wells on a platform, or even at the other end of the pipeline
5. Pressure compartments must be delineated, but often are guessed at
6. Leaky faults can deliver gas to oil reservoirs,
water to gas, and all combinations-pressure differential across
the fault is the controller.
Advantages of 4D4
1. Monitoring can obviously spot problems before
no-monitoring can. Remedial action often just involves regulation
of the choke-sizes of the various wells producing from any given
reservoir. Those chokes are not automated, and are hardly ever
changed.
2. Water incursions can be fought by selective shutting
in of wells for often very short periods of time (days). periodic
experiments, such as monitored shut-in can produce pressure rebounds
that tell detail of the far-field plumbing system. these are
never done because the pressure instruments are not in place.
3. Gas caps better be where you think they are when
you want them to be, or severe damage can be done to production.
particularly, seismic interrogation real-time is an excellent
gas locator in most rocks.
4. GOR and water mix can be controlled by injection.
Only the most sophisticated oil companies plan injection from
the start of reservoir life.
5. Pressure monitoring defines compartments than
may not be draining, producing locations for "infill"
drilling.
6. Temperatures are very sensitive to the hydrodynamics
of fluid flow. Oil and particularly gas are hugely more insulating
than water, and so are much hotter. Temperature can often tell
from how far afield the fluids are coming when nothing else can
because the temp is carried by the fluid-whereas pressure is propagated
at sonic velocities throughout the compartment. Temperatures
are never measured in ordinary oil field practices and thermistors
are the simplest of semiconductor devices, cheap, accurate, and
rugged.
D. 4D4
benefits specific to Carbonate Production
Problems in Carbonate Production
1. Degree and orientation of Fracturing controls production, but is rarely measured. Horizontal wells must be placed across natural fracture patterns.
2. Sluffing. Carbonates are often chalky, especially in permeability zones, and debris can build up and block perforations. Most perforations in general are unsuccessful.
3. Pore precipitation. Unwanted precipitates can clog perforations, such as parrafins
Advantages of 4D4
1. Steering of new wells in a field is commonplace
now. What is not is the steering of remediation wells designed
to correct drainage problems shown up by 4D4
monitoring. Drilling schedules are set
often more than a year in advance, and rapid response involving
the drilling of a new wellbore is currently not possible because
of the planning structure of oil companies. Stand-by rigs for
trouble are unheard of.
2. Monitoring of flow from inside the production
tubing can now be accomplished by live video so that instant reaction
to plugging is possible. Often, acidization can clear plugged
perfs.
E. Pressure regimes
There are two general pressure regimes - hydrostatic
and geopressured - and transitional pressure regimes in between.
Hydrostatically-pressured reservoirs require pumping to the surface
from day one. They are more expensive and less dynamic that geopressured
reservoirs that would blow-out if given an uncontrolled pathway
to the surface. Geopressured reservoirs are more dangerous.
Often, deeper production in older fields has been ignored because
oil companies do not pay much attention to added exploration targets
after the field has been transferred from the exploration office
to the production office.
Advantages of 4D4
1. Monitoring also gives deeper information about what might be revealed by new technology that is deeper than the deepest producing reservoir in an oil field. Huge opportunity to increase production here!