bluuebunny/crossref_metadata_2025 huggingface dataset:
Practical Approach in Modeling Naturally Fractured Reservoir: A Field Case Study
Authors: Bahar Asnul , Ates Harun , Al-Deeb Maged H. , Salem Salem E. , Badaam Hussein , Kelkar Mohan
Published: December 2007

This paper presents a practical approach in modeling a naturally fractured reservoir. The approach was used for a field study of a giant carbonate reservoir in the Middle East. The method is shown to be practical and comprehensive and yet has produced good results. It consists of a fully integrated effort from geological, geophysical and engineering disciplines. The overall goal of the study is to develop a representative reservoir model to form the basis for reservoir management and long-term development planning.

The approach consists of the following procedures: Generation of multiple realizations of matrix property using geostatistical techniques. The standard cosimulation procedure was implemented to ensure the consistency among reservoir properties, namely rock type, porosity and permeability.Generation of multiple realizations of 3D fracture property by reconciling seismic, well logs and dynamic data. These were obtained from curvature analysis and seismic facies map validated by borehole image and dynamic data. The fracture network was described in the reservoir as lineaments (fracture swarms) showing two major fracture trends.Calibration of the model permeability with well test-derived permeability considering fracture distribution. A newly developed technique was implemented to ensure that the fine scale model (i.e., geological model) honors well test as well as production data before it was subjected to the flow simulation. The technique also generates permeability anisotropy to account for fracture orientations.Ranking of multiple realizations using streamline simulation to select three representative realizations (low, medium and high models).Upscaling of reservoir properties, including vertical upscaling level optimization using streamline simulation.History matching and future performance prediction of the three selected realizations as a single media model. The use of single media model was based on the observation of relatively high matrix permeability in the major producing zone. However, for comparison purposes, a dual media model was also developed.Uncertainty analysis of the future dynamic performance using a probabilistic approach.

The procedure described above has been implemented successfully in a field study. The use of a calibration process in the geological model reduces the number of parameters that need to be adjusted during history matching. Consequently, history matching may concentrate on the uncertainty in parameters that have not been specifically accounted for in the geological modeling stage, such as relative permeability and aquifer size/strength.
Will Wireline Formation Tests Replace Well Tests?
Authors: Whittle T. M. , Lee J. , Gringarten A. C.
Published: December 2007

Well testing in exploration and appraisal wells has become increasingly unpopular. Reasons include costs, safety and environmental impact. Well testing has also become rare in production wells because of the potential revenue loss during build-ups. Whether suitable alternatives can be found for sampling and reservoir parameter estimation is the subject of regular debate. Alternatives are wireline formation tests in exploration and appraisal, and continuous recording with permanent pressure gauge in production wells.

The quality of pressure and rate transients measured during wireline formation tests has improved greatly in recent years. The transients obey the same laws of physics as those measured during a well test and can theoretically be interpreted in the same way. The scale of the measurements, however, is very different. The challenge is to understand what the wireline formation test interpretation results mean and how they can be upscaled to the information provided by a well test.

The paper discusses these key issues with examples that illustrate the quality of the data and the analysis process. The interpretation methods are essentially the same as those used in well test analysis with the addition of the formation rate analysis plot, which is particularly useful in high permeability formations where other methods are limited by pressure gauge resolution.
Effect of an Invaded Zone on Pressure Transient Data from Multi-Probe and Packer-Probe Wireline Formation Testers in Single and Multilayer Systems
Authors: Gok I. M. , Onur M. , Hegeman P. S. , Kuchuk F. J.
Published: December 2007

A three-dimensional r-θ-z single-phase fully-implicit finite-difference model for a vertical well has been developed to examine how the presence of invaded zones affects the multiprobe and packer-probe pressure measurements in single-layer and multilayer (crossflow) systems. Invasion zones are modeled as composite zones concentric with the wellbore, that have different rock and fluid properties (permeability, porosity, viscosity and compressibility) from those of the native uninvaded formation.

The results show that for multi-probe wireline testers, the sink (or the flowing) and horizontal probe pressure responses are highly affected by the invaded region properties, while the vertical probe pressures are mainly influenced by the properties of the uninvaded zones. For packer-probe testers, similar results are obtained; i.e., the vertical probe pressures are mainly influenced by the properties of the uninvaded zones, while the packer interval pressures at early times are influenced by the invaded zone properties. It is shown that if the invaded zones are incorporated into the interpretation process using the model developed in this work, simultaneous matching of spatially available wireline formation tester pressure data sets using nonlinear regression can provide estimates of both invaded and uninvaded zones parameters. A synthetic example of a multi-probe test is presented to confirm the theory and procedures developed in this work.
Multilayer Modeling to Define a Fluvial Sandstone Reservoir's Dynamic Structure Using Multistation Multiprobe Formation Tester Measurements
Authors: Domzalski S. , Pop J. J. , Boydell W. G. , Hadbi A.
Published: December 2007

Fluvial sandstone reservoirs display stratification and laminations which can critically affect vertical, thus horizontal, fluid movement in the reservoir during production. Understanding and quantifying in-situ permeability anisotropy and its vertical distribution, the dynamic structure of the reservoir, will dictate decisions on well construction, well completion and spacing and water and/or gas injection schemes that will ultimately impact the overall success of a field's development.

This paper looks at the application of single and multilayer transient interpretation models to multistation multiprobe formation tester measurements in order to assist in the definition of the dynamic structure of a fluvial sandstone reservoir. The common volume of the formation investigated by several of the tests afforded the opportunity to compare the predicitions of various formation models.

The paper is an extension of a case history8 from an Algerian fluvial sandstone oil-bearing reservoir where near to 60 in-situ measurements of permeability anisotropy, Kv /Kh, were obtained by running vertical interference tests (VITs) with a multiprobe formation tester during openhole (OH) logging operations. The formation tester, configured with four probes and a recyclable constant rate flow module, was used to perform, on average, 10 VITs per well for several key wells in the field. The spatial arrangement of the probes employed when set against the wellbore at each test station allowed simultaneous, overlapping measurements of permeability anisotropy to be performed on 0.70 meter and 3 meter length scales (the latter dimension being similar to vertical grid block sizes used in field reservoir simulators). These measurements provided Kv / Kh ratios in homogeneous "clean" sections of the sedimentary units investigated and information on sealing properties of tight streaks, shales, laminations and "dirty" sections straddled by the probes through the determination of the "effective" values of Kv / Kh.

The paper considers an llmeter lithological unit, within a 60 meter reservoir section, from one well where four stations were tested with the multiprobe formation tester. (The complete logging operation consisted of 10 stations over the 50 meters of net pay.) The llmeter lithological unit is made up of "clean" sandstone layers interspersed with "dirty" sections and high density "tight" streaks. Multilayer (crossflow-layered) pressure transient interpretation was applied to the data acquired with the multiprobe formation tester (four stations), incorporating single layer interpretation results as well as measured petrophysical and geological data. A simple limited-extent permeability barrier model also assisted in better understanding the lateral extent of a hydraulically semi sealing "streak". The results derived from these more complex analyses are compared to the "equivalent" single layer interpretation results.
The Reduction of Near Zone Effects on the Multi-component Induction Logging Tool
Authors: Yu Liming , Rabinovich Michael , Tabarovsky Lev , Wang Tshili
Published: December 2007

The multi-component induction tool (3DEX) developed by Baker Atlas is comprised of three mutually orthogonal transmitter-receiver pairs measuring the secondary magnetic field at ten different frequencies. The measured data include the conventional coaxial component, Hzz, parallel to the borehole axis, and two coplanar components, Hxx and Hyy, perpendicular to the wellbore. In addition, two crosscomponents, Hxy and Hxz, are acquired to determine the formation dip and azimuth angles. The objective of this tool is to derive the horizontal and vertical resistivities of thinly laminated sand/shale sequences and anisotropic sands.

The tool responses are influenced by near zone anomalies, such as drilling mud, elliptic invasion, drilling induced fracture, and tool eccentricity. Because the tool uses a relatively large transmitter-receiver separation, the near zone effects are fairly small on the coaxial component, Hzz, but they remain strong on the coplanar components, Hxx and Hyy.

To reduce the near zone effects, a multi-frequency data processing technique was developed. We validated the technique with synthetic data produced by both 2-D and 3-D modeling algorithms. In an example of the borehole effect, the relative difference in responses with and without the borehole is 22% in the single frequency data but only 0.1% in the multifrequency processed data. In an example of the eccentricity effect, the relative difference in responses with and without tool centralization is 213% in the single frequency data but reduced to only 0.3% in the multi-frequency processed data. Therefore, after the multi-frequency data processing, a simple 1-D vertically layered model can be utilized for data interpretation because much of the near zone effects have been removed. The applicability of the MFF technique is limited in highly resistive formations due to a decreased signal-to-noise ratio as a result of the hardware noise.
The United Nations Framework Classification for World Petroleum Resources
Authors: Ahlbrandt T. S. , Blystad P. , Young E. D. , Slavov S. , Heiberg S.
Published: December 2007

The United Nations has developed an international framework classification for solid fuels and minerals (UNFC). This is now being extended to petroleum by building on the joint classification of the Society of Petroleum Engineers (SPE), the World Petroleum Congresses (WPC) and the American Association of Petroleum Geologists (AAPG).

The UNFC is a 3-dimansional classification. This: Is necessary in order to migrate accounts of resource quantities that are developed on one or two of the axes to the common basis;Provides for more precise reporting and analysis. This is particularly useful in analyses of contingent resources.

The characteristics of the SPE/WPC/AAPG classification has been preserved and enhanced to facilitate improved international and national petroleum resource management, corporate business process management and financial reporting.

A UN intergovernmental committee responsible for extending the UNFC to extractive energy resources (coal, petroleum and uranium) will meet in Geneva on October 30th and 31st to review experiences gained and comments received during 2003. A recommended classification will then be delivered for consideration to the United Nations through the Committee on Sustainable Energy of the Economic Commission for Europe (UN ECE).
Significant Differences in Proved Reserves Volumes Estimated Using SPE/WPC Reserves Compared to United States Securities and Exchange Commission SEC Definitions
Authors: Harrell D. R. , Gardner T. L.
Published: December 2007

A casual reading of the SPE/WPC Petroleum Reserves Definitions (1997) and the U.S. SEC definitions (1978) would suggest very little, if any, differences in the quantities of hydrocarbon reserves estimated under those two classification systems. The differences in many circumstances for both volumetric and performance-based estimates may be small.

In 1999, the SEC began to increase is review and en-forcement process, seeking greater understanding and compliance with its oil and gas reserves reporting requirements. The agency's definitions were promulgated in 1978 in connection with the Energy Policy and Conservation Act of 1975 and at a time when most publicly owned oil and gas companies and their reserves were located in the United States. Oil and gas prices were relatively stable and virtually all natural gas was marketed through long-term contracts at fixed or determinable prices. Development drilling was subject to well-spacing regulations as established through field rules set by state agencies.

Reservoir evaluation technology has advanced far beyond that used in 1978; production-sharing contracts were uncommon then and probabilistic reserves assessment was not widely recognized or appreciated in the U.S. All of these factors plus numerous other considerations continue to create continuing unsolved problems in adapting the application of 1978 vintage definitions to the technological realities of 2003, particularly in light of the business and economic climate in the U.S. and around the world.

This paper presents several real-world examples of how the SEC engineering staff has updated its approach to reserves assessment as well as numerous remaining, unresolved areas of concern. These remaining issues are important, can lead to significant differences in reported quantities and values and may result in questions about the "full disclosure" obligations to the SEC.
Horizontal Openhole Gravel Packing in a Depleted and Heterogeneous Reservoir
Authors: Onwusiri Henry , Onwuzurike Chiji , McPike Tim , Jansen Rene
Published: December 2007

Open-hole gravel packing in vertical/conventional wells is an accepted sand exclusion method that has not gained wide and rapid application in horizontal wells. The reason is largely due to sand placement challenges in the horizontal drain that could lead to premature sand screen-out. Consequently, many operators are skeptical gravel packing horizontal wells since failure could probably result in enormous capital risk. In the Niger Delta, about 70 % of the hydrocarbon-bearing reserves lie in shallow unconsolidated reservoirs where the sonic transit time vary between 110 to 140 us/ft. Production from these intervals has proven record of sand threats to operating cost, well integrity, surface facilities and production sustenance. The challenge is to complete wells in these reservoirs with sand exclusion materials that would guarantee full life-cycle production performance.

Early horizontal wells in the region were completed with stand-alone screens, but recently, the expandable sand screen (ESS) took a leading edge. Though the ESS has a higher inflow area compared to other screens, its high cost, lack of full-bore expansion and the required lead-time continue to raise concerns especially when considered for applications in brown field development where well potential and reserve rewards are low. In response to these concerns, in 2002, openhole gravel packing (OHGP) in a horizontal well was investigated and considered as an alternative sand exclusion option in Shell Petroleum Development Company (SPDC). The trial candidate, the Obigbo-North QWSB-3 was selected and successfully completed as the first horizontal OHGP in SPDC using the alpha-beta wave concept.

Based on simulation results, about 9237 lbm of sand was planned for placement in 1000-ft of 6.0-in hole size, however, the actual sand pumped was about 10830 lbm. This represents an estimate of 6.25-in drain hole size. The application saved over $0.3 million when compared to the cost of using ESS. For the Eastern asset team that drills an average of 12 wells annually, an annual projected completion cost-saving of some $3.6 million is achievable.

Based on the initial production testing, Obigbo-North Well QWSB-3 tested 3250 BOPD with a productivity index (PI) of 130 bbl/(psi-D). Baseline Memory Production Logging Tool (MPLT) logging showed that the entire drain section completed on the clean sand member had effective inflow into the linerbore. In addition to establishing confidence in the application and performance efficacy of OHGP, this trial and the significant cost-savings will engender a paradigm shift to horizontal well sand control. In this presentation, we will share some data and results based on field experiences, challenges and new understanding.
Compositional Modeling of Gas Injection With Three Hydrocarbon Phases for Schrader Bluff EOR
Authors: Wang Yun , Lin Cheng-Yuan , Bidinger Curt , Muralidharan Venkataramanan , Lee Sheng-Tai
Published: December 2007

A comprehensive analysis of Schrader Bluff viscous oil EOR performance is presented in this paper using the newly developed three-hydrocarbon-phase (3 HC) compositional table look-up approach. The unique combination of viscous oil, low reservoir temperature and high level of CO2 in the miscible injectant (MI) gives rise to the formation of 3 HC phases in the field operating pressure range for the Schrader Bluff EOR processes in Alaska. The numerical difficulties associated with the presence of 3 HC phases are well documented in the literature. A new 3 HC-phase compositional table look-up option within a commercial compositional simulator was developed to cope with these numerical difficulties. The application of this new approach in the Schrader Bluff EOR evaluation serves as the first field-scale validation of such approach. The analysis presented in this paper contains three parts. First, 1D slimtube models are built using both a 3 HC-phase slimtube simulator and the compositional table look-up option to validate the new approach. Then a 2D well-pair model is constructed to investigate the effect of gravity segregation. Optimal vertical gridding and WAG schedule are determined as a result of the 2D analysis. Finally, a 3D field-scale pad model is used to predict the EOR performance. In addition, a simplified methodology is developed to calculate the returned MI production for Schrader Bluff. The 3D results show that the 3 HC-phase compositional look-up methodology can be applied to field-scale processes for which other approaches for handling 3 HC-phase flow are either numerically unstable or too time consuming.
Horizontal Well Design Optimization: A Study of the Parameters Affecting the Productivity and Flux Distribution of a Horizontal Well
Authors: Vicente Ronaldo , Sarica Cem , Ertekin Turgay
Published: December 2007

With the widespread applications of horizontal wells and its successful performance in the last decade, a number of relevant questions has been raised with respect to the optimization of horizontal well design. Considering the high costs involved and the technical challenges that are faced by the industry under various scenarios such as offshore environment, unconsolidated sands and heavy oil production, questions related to the optimization protocols to be followed have become progressively more important and more difficult to answer. Thus, the task of optimizing horizontal well design requires an investigation of the parameters that affect the productivity and ultimately the behavior of both reservoir and horizontal well domains, as well as the risks and costs involved in each alternative.

Based on a fully implicit, three-dimensional numerical model coupling reservoir and horizontal well flow dynamics, a detailed study of the parameters that affect the behavior of flux distribution and productivity along horizontal wells has been performed. The parameters analyzed include permeability, initial gas saturation, anisotropy ratio, well location, fluid viscosity, flow rate, well length, and well diameter. A tool that permits to compare and select the potential options in terms of the gain in productivity per additional unit of well length and diameter is also introduced.

Validation of the numerical model used in this study is performed using production-logging data and the examples of results of the application of the optimization protocol developed are reported for some of the Petrobras offshore fields.
Experimental and Simulation Studies of Steam-Propane Injection for the Hamaca and Duri Fields
Authors: Mamora D. D. , Rivero J. A. , Hendroyono A. , Venturini G. J.
Published: December 2007

Studies have been conducted to evaluate the feasibility of steam-propane injection for the Hamaca heavy oilfield (8°API) and for the Duri intermediate oilfield (20°API). The experiments involved injecting steam simultaneously with propane at the top of a vertical cell containing a mixture of sand, oil and water. Superheated steam was injected at 170°C and 3.5 ml/min (Hamaca) and 260°C and 5.5 ml/min (Duri), with the cell outlet pressure at 50 psig (Hamaca) and 500 psig (Duri). Runs were made with propane:steam mass ratios (PSR's) ranging from 0:100 to 10:100. With steam-propane injection (PSR 0.05): (i) start of oil production is accelerated by 23% (Hamaca) and 30% (Duri), (ii) steam injectivity is up to three times higher, and (iii) steam front velocity is higher, indicating greater partitioning of the distilled fractions into the propane stream that appears to act as an efficient carrier gas.

A simulation study was conducted using a 1D 48 grid-cell model with a ten pseudo-component oil model for the Hamaca oil. Satisfactory history matches of the experimental runs were obtained; C7 – C10 appear to play a significant role during steam-propane injection. A reservoir simulation study was performed using a 9 × 5 × 10 3D Cartesian model representing one-eighth of a 10-acre 5-spot pattern. Five-year forecast runs were made with well steam injection rate of 600 BPDCWE. Production is enhanced with steam-propane injection (PSR0.05) as follows: (i) start of oil production is accelerated by 20%, (ii) oil production peak with steam-propane injection (1100 STB/D) is significantly higher than that with pure steam injection (690 STB/D), (iii) oil production acceleration increases with propane content, (iv) oil recovery is about three times that with pure steam injection, indicating improved sweep/displacement efficiency with steam-propane injection.
Enzyme Breaker Technologies: A Decade of Improved Well Stimulation
Authors: Brannon Harold D. , Tjon-Joe-Pin Robert M. , Carman Paul S. , Wood William D.
Published: December 2007

Fracturing fluids are most commonly aqueous systems comprising various polymers and crosslinking agents added to facilitate effective proppant transport and placement. A goal of fracturing practitioners has been to apply breaker technologies effective to eliminate or minimize the residual gel damage left behind by such systems in order to optimize the well stimulation. As a result of R&D efforts to that end, polymer-linkage-specific (polymer-specific) enzyme breakers were first introduced for fracturing applications in 1992. To date, these enzyme breakers have been employed in thousands of fracturing treatments around the world. Recent case studies evaluating long-term cumulative production have shown that wells in which polymer specific enzyme breakers have been applied demonstrate extraordinary performance when compared to production from offsets using other technologies. The long-term success of polymer-specific enzymes in fracturing operations for improving long-term production has been predicated upon a number of characteristics unique to enzymes, including their specificity to target polymer linkages and their functionality as catalysts which are not "spent" in the reactions they initiate. Additionally, contrary to popular misinformation, enzymes are effective at extremes of pH and temperature when properly applied. These unique properties are thought to make polymer-specific enzymes the polymer-degradation additive, which would produce the most effective proppant pack, thereby maximizing long-term productivity.

The numerous case histories and offset comparisons documented in previous studies were, as a rule, relatively short-term in the prospective life of a well. The current endeavor seeks to provide detailed follow-up analyses of truly long-term production data from 170 fracture stimulated wells in the Canyon Sand, Penn, Lobo-Wilcox, Redfork, Hosston, and Grayburg/SanAndres formations and, the deep McKittrick field. Production histories over periods of up to 8 years were evaluated on wells treated with the polymer-specific enzymes and compared to offsets completed using conventional breaker technologies. The results clearly demonstrate the benefits of application of polymer-specific enzyme breakers on long-term well productivity.
On Reservoir Fluid-ow Control with Smart Completions
Authors: Ramakrishnan T. S.
Published: December 2007

Poor displacement efficiency in hydrocarbon formations is often due to the natural variation in the mobility of fluids across the reservoir strata. Historically, completions with cemented casing, packers, and selective perforations have been used to mitigate the disparities in water encroachment over the reservoir interval. Recently, completion technologies using downhole valves allowing production and injection control over multiple zones have become available. The central idea is that the downhole control may be used to adjust flow distributions along the wellbore to correct undesired fluid-front movement.

In this paper, we address several technical issues related to downhole controls. We consider the completion, the reservoir, the measurement, and the feedback algorithm that adjusts flow-control devices as a single system with quantitative models for each of the components. Both pressure and flow-rate control systems are discussed. Downhole control is modeled for electrical, reversible hydraulic and unidirectional hydraulic valves. System design requires a quantitative description of both the orifices in the control valves, and the feedback control algorithm. The design methodology for different valve systems is described and the disadvantages of hydraulic systems are discussed. In particular, it is shown that in conjunction with an automated feedback control, hydraulic valves will oscillate. Computations also show that all other factors remaining equal, these oscillations occur most easily in low permeability zones. We also illustrate novel anticipatory control algorithms that prevent overshooting with unidirectional hydraulic valves.

For layered systems that communicate, a front movement equation is derived using perturbation techniques. This technique provides the zone of influence of wellbore flow control devices, and illustrates the maximal benefit that may be obtained through downhole control, and hence provides a ready comparison of the benefit with completion costs.
A Design Approach for "Self-Lifting" Method to Eliminate Severe Slugging in Offshore Production Systems
Authors: Tengesdal J. Ø. , Thompson Leslie , Sarica Cem
Published: December 2007

Recently, exploitation of offshore petroleum reservoirs has moved to ever increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deep-water risers that conduct production from multiple wellheads on the sea floor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. Considering the length of the deep-water risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences such as premature field abandonment, loss of recoverable reserves and earlier-than-planned deployment of boosting devices.

In this study, a novel idea to lessen or eliminate severe slugging in pipeline-riser systems has been investigated. The principle of the technique is to transfer the pipeline gas to the riser at a point above the riser-base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the pipeline, consequently lessening or eliminating the severe slugging by maintaining the steady-state two-phase flow in the riser.

In this paper a steady state model is presented. It can be used as a design tool for the self-lifting concept by determining the operation envelope for successful self-lift operation given the location of the gas takeoff or injection points; it can predict the acceptable range of pressure losses in the gas bypass for continuous steady-state operation of the self-gas-lift system. The model was found to perform very well when compared to the acquired experimental data.
Effects of Pressure and Pipe Diameter on Gas-Liquid Two-Phase Flow Behavior in Pipelines
Authors: Abduvayt P. , Manabe R. , Arihara N.
Published: December 2007

The effects of pressure and pipe diameter on gas-liquid two-phase flow behaviors were investigated experimentally and theoretically for horizontal and slightly inclined pipelines. Experimental data of flow pattern, pressure drop and liquid holdup were acquired in the wide range of the gas and liquid flow rates in a large diameter (106.4 mm) pipe for different pressures (592 and 2060 kPa) and different inclination angles (0°, 1°, and 3°). To evaluate effects of the pipe diameter, our previous experimental data of low pressure (490 kPa) and small diameter (54.9 mm), were also used. Based on analysis of the experimental observations, a flow pattern map was developed for each pressure, pipe diameter, and inclination.

Major phenomena identified in data analysis include: Pressure and pipe diameter clearly affect the flow pattern transition boundaries. The high pressure tends to shift the boundaries to the lower side of superficial gas velocity in the flow pattern maps. In the large-diameter-pipe experemints, stratified flow was observed at higher superficial liquid velocities than in small diameter. The gas flow rate and inclination angle showed influences on liquid holdup and pressure drop behavior. The average pressure did not show large influences on liquid holdup and pressure drop.

Based on the experimental data, a mechanistic model was developed incorporating transition criteria for eight flow patterns, and individual flow models for estimating liquid holdup and pressure drop. The results predicted by the individual models demonstrated excellent agreements with the experimental data for each pressure and each inclination angle.
Shrinks or Quants: Who Will Improve Decision-Making
Authors: Begg S. H. , Bratvold R. B. , Campbell J. M.
Published: December 2007

Uncertainty is the underlying cause of the failure of many decisions to deliver their promised technical and economic metrics. Are these failures, despite the increased application of tools and processes for decision-making under uncertainty over the past decade, due to bad decisions or just bad outcomes? This paper examines quantitatively the validity of the assumptions underlying current decision tools and processes, and the extent to which their application accounts for the risks that arise from uncertainty. We also quantify the impacts of prevalent human biases and cognitive limitations on our ability to make decisions that are logically consistent with our objectives. We conclude that the above factors can have a large impact on the outcomes of decisions and therefore bad process, not just bad luck, is a major cause of disappointing results. More awareness is needed of the capabilities and limitations of common decision-making making techniques, and of the psychological and judgemental factors that influence their application.
Optimizing Multiple-Field Scheduling and Production Strategy with Reduced Risk
Authors: Cullick A. S. , Heath David , Narayanan Keshav , April Jay , Kelly James
Published: December 2007

Large, multiple-field Exploration & Production (E&P) assets require long-term commitments of capital that are tied to decisions on facilities, wells, scheduling, and production strategy. The decisions often must be made when there are high uncertainties, leading to risks. This paper presents a system which integrates finite-difference reservoir simulation, an economics model, and a Monte Carlo algorithm with a global optimization search algorithm to identify more optimal reservoir planning and management decision alternatives under conditions of uncertainty, such that the associated risks are managed. The optimization problem is posed with the business goals stated as a general objective function and includes all constraints (economic, reservoir, production, and statistical) that need to be honored.

The method is illustrated with an example of an E&P asset with multiple oil fields produced through a common surface network. The formulation of the example problem includes decision variables for the scheduling of reservoir units, the number of wells, and production rate capacities. It incorporates the nonlinear response of the objective to reservoir performance and surface pressure constraint through a flow simulator. The analysis is multi-period, evaluating the impact of predicted performance over time for each decision alternative. The individual reservoir units have uncertainties in hydrocarbon volumes and quality, reservoir deliverability, and costs. Decision solutions for objective functions of net present value (NPV) that mitigate risks are presented.
Design and Long-Term Production Performance of Frac Pack Completions in a Gulf of Mexico Deepwater Turbidite Field Having Inverted Sand-Shale Stress Contrasts: Case History
Authors: Shumbera David A. , Ellis Richard C. , Loya Darrell
Published: December 2007

Several sand control completions in the initial development of a Gulf of Mexico deepwater turbidite field failed prematurely when placed on production. After an extensive multi-discipline review of completion designs and procedures, the cause of these completion failures was determined to be an inverted sand-shale stress contrast, that is, shales were at lower minimum horizontal stress than adjoining sand layers. Direct evidence of this sand/shale stress reversal was obtained from mechanical strength property data derived from dipole sonic logs in two wells in this field.

Frac pack completion design was modified to account for this sand/shale stress reversal by incorporating perforation standoff from adjacent shales and by using smaller pad volumes. The modified design was successful in achieving excellent frac packs in seven subsequent completions in this field. Long-term performance of these modified frac pack completions has been excellent.
Sand Control Completion Reliability and Failure Rate Comparison With a Multi-Thousand Well Database
Authors: King George E. , Wildt Pat J. , O'Connell Eamonn
Published: December 2007

Through inter- and intra-company cooperation, an Excel database has been constructed with sand control reliability/failure information on over 2000 wells. The database makes possible the study of completion performance and the comparison of reliability for various forms of sand control, and common causes for sand control completion failures. This paper shares the general reliability results of this database without any reference to producing company name, service provider names or product names. The database contains information regarding general reliability and has information from many wells on cumulative production, maximum rates, drawdown, skins, pay deviation, screen length, and pay interval sorting, fines content, depth and length. The database is open to any company willing to share anonymous well data. There are no costs, no contracts and no meetings.
South Texas Hybrid Monobore High Pressure, High Temperature Well Design
Authors: Billa Rich , Gordon Doug , Watterson Ed , Mota Jose
Published: December 2007

Adopting tubingless and Hybrid Monobore well designs in the Fandango Field, Shell's most hostile high pressure, high temperature (HPHT) field in South Texas, has reduced drilling and completion costs by 30%. These designs and the cost savings they generate are allowing the development of the mature gas field to continue.

The tubingless design is now used in Fandango for wells with shut-in tubing pressures (SITP's) up to 11,000 psi. The Hybrid Monobore, a modified tubingless design, provides an additional pressure barrier and is run in wells with SITP's approaching 14,000 psi.
A Case Study of a Fine Scale Integrated Geological, Geophysical, Petrophysical, and Reservoir Simulation Reservoir Characterization with Uncertainty Estimation
Authors: Hamman J. G. , Buettner R. E. , Caldwell D. H.
Published: December 2007

A novel method for the integration of multi-scale rock and fluid information was performed on a single well deep-water exploration discovery. The method integrates diverse data types through physically constrained models into a single earth model. Development scenarios were optimized through multiple flow simulations. The development scenarios were designed to investigate the range of uncertainty in the earth model. This technique utilizes a single integrated earth model and multiple simulations in contrast to techniques that cannot reproduce the seismic, or reproduce the seismic but require a flow simulation for each geologic "realization".

The pending business decisions required reservoir characterization with the greatest precision possible and an understanding of the inherent uncertainties. The discovery was made based on 3-D seismic amplitudes, but a portion of the potential reservoir appeared to be obscured by a shallower seismic event. The available borehole data with which to construct the earth model consisted of conventional wireline logs and a wireline-conveyed formation tester from a single penetration. No flow tests, core or fluid samples were available.

The technique honors all the observed data through the alteration of an initial geologic model until, through up-scaling, an acceptable match is made with acoustic impedance determined from the observed seismic. The link between the geology and seismic is a rock physics model consistent with the well data.

The rock physics model is used to estimate the equivalent seismic properties from the porosity and fluid saturations in the fine scale geologic model. The objective is to minimize the difference between acoustic impedance generated from the 3-D seismic data and the forward-modeled very-fine scale geologic model. The uncertainties associated with each measurement and derived variables were assessed at each step. The resulting model will reproduce the original seismic amplitude data and all of the well data, although the well data were not explicitly used in the seismic inversion or the "inversion-of-the-inversion" estimation of petrophysical properties. Each cell in the resulting fine-scale geologic model contains porosity, permeability, and oil saturation.

The static model was up-scaled for dynamic flow simulation to estimate productivity and evaluate various development schemes. Numerous simulations were performed to address uncertainties in the geologic model and to account for risks associated with the geophysical imaging problems, and flow capacity. Two sets of distributions were assigned to porosity and permeability in the simulator for separate areas of the reservoir. A distribution was also assigned to fault transmissibility. The results of hundreds of simulator realizations were then used to estimate the range of uncertainty in reservoir performance under varied development scenarios.
Permeability Estimation Functions Based on Forward Modeling of Sedimentary Heterogeneity
Authors: Ringrose Philip S. , Skjetne Erik , Elfenbein Carsten
Published: December 2007

Effective permeability in the inter-well reservoir volume is notoriously difficult to estimate due to its scale dependence and sensitivity to heterogeneity. Using stochastic models of realistic 3D sedimentary heterogeneity at the 10cm to 10m scales, we established a series of functional relationships between effective permeability, bedding type and volume fraction (sand, mud, etc.). These functional relationships (bedding type curves) can be understood in terms of effective medium and percolation theory for mixed sand/mud systems, and are a significant improvement of conventional averaging procedures. The functions can be integrated with core plug and wireline data to give improved initial property estimates of the reservoir volume. We applied the method in field studies from several heterolithic reservoir formations of the Norwegian Sea. Improved estimates of vertical permeability are found to be particularly valuable for interpreting unexpected production data and dynamic reservoir history.
A Geostatistical Method for Characterizing Superpermeability from Flow-Meter Data: Application to Ghawar Field
Authors: Voelker Joe , Liu Jim , Caers Jef
Published: December 2007

This paper presents the application of multiple point geostatistical modeling, combined with a new technique for model perturbation, to characterize abnormally high flow capacity geologic features, super-k, within an 11-well study area in a large, Middle Eastern, carbonate reservoir. The reservoir characterization adequately history matches well flow-meter data measured in 2 surveys, taken over a 3 year period, obtained in 2 of the study area wells.

Characterization of the abnormal flow features is desired for future placement of water injection or production wells, to decrease the probability of wells being completed in the abnormal features, avoiding quick water breakthrough. The high conductivity features are an aggregation of two principle geologic components: high permeability beds of various lithologies, and high conductivity discrete fractures. These components form a flow network of unusually high conductivity, often much higher than predicted from flow capacity calculations in wells intersecting the network.

Simulation of flow in the discrete fractures is performed using well models. Well models offer several advantages over fracture discretization and dual porosity models, for flow simulations performed as part of an optimization algorithm.

A training image of facies architecture is developed based on conceptual depositional models of the reservoir. Using multiple-point geostatistics, various geologically realistic reservoir models can be generated, constrained to facies data from wells. Discrete fractures are associated with certain elements of the facies model, and therefore are added stochastically. A history match of flow-meter data is obtained with a single parameter optimization of the geostatistical model realizations, using a technique in which facies probabilities, rather than facies events, are perturbed. This method maintains integrity to the underlying geological model, while history matching, hence making prediction of future super-k occurrences possible.
A Novel Methodology to Derive the Dimensions and Degree of Containment of Waterflood-Induced Fractures From Pressure Transient Analysis
Authors: van den Hoek P. J.
Published: December 2007

It is well established within the Industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected –either for voidage replacement or disposal-large fractures may be induced over time.

The current paper aims to provide a methodology for Injection Fall-Off (IFO) test analysis of fractured (produced) water injection wells. Some essential elements of IFO for fractured water injectors are: Closing fracture, (early) transient elliptical reservoir fluid flow, finite fracture conductivity, and fracture face skin.

An exact semi-analytical solution is presented to the fully transient elliptical fluid flow equation around a closing fracture with finite conductivity, fracture face skin, and multiple mobility zones in the reservoir surrounding the fracture. This solution also captures the case that during closure the fracture is generally shrinking from adjacent geological layers under higher in-situ stress. Based on this solution, type curves of the dimensionless bottom-hole pressure as a function of dimensionless time are provided covering both the period during fracture closure / shrinkage and the period after fracture closure. The shape of these type curves is studied as a function of the different relevant parameters, in particular the fracture compliance, the height of in-situ stress contrasts, fracture face skin, fracture closure time, and injection period. It is shown how the fracture length and height, and the degree of fracture containment (in combination with the heights of the stress contrasts) can be derived from these type curves. It is also demonstrated that the analyses based on the storage flow and linear flow regimes need to be integrated into one analysis method in order to obtain consistent results.

Finally, the concepts developed in this paper are applied to a number of field examples, where the dimensions and degree of containment of the induced fractures are derived from the analysis of the IFO data.
Combined Use of X-ray CT Scan and Local Resistivity Measurements: A New Approach to Fluid Distribution Description in Cores
Authors: Durand Claudine
Published: December 2007

Continuous local resistivity measurements along a plug are combined with observations by CT-scan during the "plateaux" of a "steady state" procedure, as well as during "unsteady state" procedures at the end of the drainage or imbibition. This improves the consistency of the description of the experiment, allows the selection of the zones where the fluids are actually homogeneously distributed, and thus the quality of the RI-Sw relationship that can be drawn from these experiments, and which may be of paramount importance in the log interpretation. Identification of non-homogeneous zones can bring some ideas about mechanisms of fluid flow. Following a work on homogeneous Fontainebleau sandstones, examples are given on heterogeneous carbonates.