bluuebunny/crossref_metadata_2025 huggingface dataset:
3D Porosity Modeling of a Carbonate Reservoir Using Continuous Multiple-Point Statistics Simulation
Authors: Zhang T. , Bombarde S. , Strebelle S. , Oatney E.
Published: December 2007

Training images are numerical representations of geological conceptual models that provide prior information on reservoir architecture. A new emerging geostatistical approach named multiple-point statistics (MPS) simulation allows extracting multiple-point structures from such training images and anchoring these structures to the data actually observed in the reservoir. By reproducing multiple-point statistics inferred from training images, MPS enables the modeling of complex curvilinear structures, for example sinuous channels, in a much more geologically-realistic way than traditional two-point statistics or variogram-based techniques. However, in the original MPS implementation, all multiple-point statistics moments computed from the training image are exported to the reservoir model without processing, which allows simulating only categorical or discretized variables. This implementation is appropriate with clastic reservoirs for which, typically, depositional facies are simulated first using MPS, then porosity and permeability are distributed within each simulated facies using traditional variogram-based techniques. But for reservoirs, in particular in carbonate environments, where porosity and permeability trends/cycles are not closely tied to any facies distribution, simulating porosity/permeability directly using corresponding continuous training images appears to be a more suitable approach.

In this paper, a new filter-based implementation of MPS is proposed to reproduce features from continuous variable training images. First, a set of general filters is applied to the training image to transform (summarize) each training pattern into a set of scores accounting for different aspects of the pattern, such as north-south and east-west gradients and curvatures. The training patterns are classified in the score space, and grouped into a small number of similarity classes. The simulation consists then of visiting each grid node along a random path, identifying the similarity class that best fits to the local conditioning data, and patching a pattern drawn from the selected similarity class. In our study, this new approach was applied to model the 3D porosity distribution of a carbonate reservoir in Kazakhstan. First, the original "categorical" MPS program was used to model the two main reservoir regions, platform and slope, where the spatial porosity distribution is characterized by significantly different features. Interpreted well markers and seismic data were used to condition the modeling of these two regions. Then porosity was distributed in each region using the "continuous" filter-based MPS program described above. The 3D training images used in that second step displayed porosity trends/cycles controlled by the type of geological sedimentation process believed to have occurred in the reservoir.
Want To Make Tree Operations Safer? Why Not Use the DHSV as a Barrier?
Authors: Munday K. , Trim S. , Turna E. P.
Published: December 2007

Industry practice for the design and operation of oil and gas producing wells incorporates a two-barrier policy, and defines an integrity envelope for environmental protection and safe operations. The standard practice when removing or undertaking major operations on the Xmas tree is to set one or more plugs in the production tubing to maintain two barriers between the reservoir and the environment.

This paper assesses the relative risk of using a Down Hole Safety Valve (DHSV) as a qualified barrier during such operations. Quantitative Risk Assessment (QRA) has been used in this study to understand the implications of the change in working practices.

QRA has been used to assess the risks of an uncontrolled flow of fluid from the reservoir when using a qualified DHSV as a barrier as compared to the standard practice of setting one or more wireline plugs. Three representative cases have been considered in this study:

Case 1

examines changing valves downstream of the master valve on a sub sea well.

Cases 2 and 3 focus on platform wells.

Case 2

changing valves downstream of the lower master valve, and

Case 3

removing the Xmas tree.

The study shows that the major risk when using a wireline set plug as a downhole barrier arises from the blowout risk associated with wireline operations. Use of a DHSV as a qualified barrier eliminates the wireline blowout risk, and reduces the overall risk during Xmas tree operations. Hence, the study recommends the use of a qualified DHSV as a barrier, subject to a risk assessment on a case by case basis.
Selection and Evaluation Criteria for High-Performance Drilling Fluids
Authors: Morton K. , Bomar B. , Schiller M. , Gallet J. , Azar S. , Dye W. , Daugereau K. , Hansen N. , Otto M. , Leaper R. , Shoults L.
Published: December 2007

The degree of difficulty and costs of oil and gas wells have continually increased over the past decade. Development operations continue as the economics of exploring and producing for oil and gas have improved with advancements in drilling technology. Advanced drilling technologies such as rotary stearable assemblies, logging-while-drilling (LWD) tools, annular pressure subs and new bit designs have improved the economics of performance-driven wells. With consideration of reducing drilling problems such as torque and drag, stuck pipe, low rates-of-penetration, depleted sands and well bore stability; these wells are generally drilled with non-aqueous fluids (NAF). However, the inherent advantages provided by NAF are increasingly being offset by environmental risks and liabilities.

The paper discusses key criteria to be considered when selecting high performance fluids (HPF) for performance-driven wells. Performance-driven wells are classified as wells that are technically challenging and inherently risky and costly. These types of wells demand the use of HPF to contain costs and deliver well objectives. Additionally, a new high-performance water-based mud (HPWBM) has been developed and field tested as a technically competent and environmentally compliant alternative to NAF on performance-driven wells. Through a process of product substitution, ChevronTexaco has achieved project objectives while improving the environmental impact of using HPF.
Analysis of the Ensemble Kalman Filter for Estimation of Permeability and Porosity in Reservoir Models
Authors: Lorentzen R. J. , Nævdal G. , Vallès B. , Berg A. M. , Grimstad A.-A.
Published: December 2007

It has lately been reported several successful applications where the ensemble Kalman filter has been used to estimate reservoir properties such as permeability and porosity. However, a thorough investigation of robustness and performance is still missing for this approach. In this paper we aim at filling this gap by studying the robustness of the methodology. One aspect which is investigated is how the filter depends on the initial ensemble. As the initial ensemble is created in a stochastic way, one can not be certain that the results obtained from one run represent the filter performance. Another aspect of interest is how prior information can be used to obtain best possible initial fields. The influence of geostatistical information on the estimated solutions is studied. In addition, the quality of the estimated fields is investigated by evaluating if the estimated static fields are reasonable when treated as the solution of the history matching problem.

The estimation technique has been applied to the widely used PUNQ-S3 reservoir model, which is a small size synthetic 3-D reservoir engineering model. Both permeability and porosity are tuned, and measurements consist of well bottom-hole pressures, water cuts and gas-oil ratios. The initial fields are conditioned on the porosities in the gridblocks where the wells are located. By using a synthetic reservoir model it is possible to calculate the uncertainty of forecasts, and compare this with the true solution.
Streamline Tracing on General Triangular or Quadrilateral Grids
Authors: Matringe S. F. , Juanes R. , Tchelepi H. A.
Published: December 2007

Streamline methods have received renewed interest over the past decade as an attractive alternative to traditional finite difference simulation. They have been applied successfully to a wide range of problems including production optimization, history matching and upscaling. Streamline methods are also being extended to provide an efficient and accurate tool for compositional reservoir simulation. One of the key components in a streamline method is the streamline tracing algorithm. Traditionally, streamlines were traced on regular Cartesian grids using Pollock's method. Several extensions to distorted or unstructured rectangular, triangular and polygonal grids have been proposed. All of these formulations are, however, low-order schemes.

Here we propose a unified formulation for high-order streamline tracing on unstructured quadrilateral and triangular grids, based on the use of the stream function. Starting from the theory of mixed finite element methods, we identify several classes of velocity spaces that induce a stream function and are therefore suitable for streamline tracing. In doing so, we provide a theoretical justification for the low-order methods currently in use, and we show how to extend them to achieve high-order accuracy. Consequently, our streamline tracing algorithm is semi-analytical: within each gridblock the streamline is traced exactly. We give a detailed description of the implementation of the algorithm and we provide a comparison of low- and high-order tracing methods by means of representative numerical simulations on two-dimensional heterogeneous media.
Applications of the Coefficient of Isothermal Compressibility to Various Reservoir Situations With New Correlations for Each Situation
Authors: Spivey J. P. , Valko P. P. , McCain W. D.
Published: December 2007

The coefficient of isothermal compressibility (oil compressibility) is defined as the fractional change of oil volume per unit change in pressure. Though the oil compressibility so defined frequently appears in the partial differential equations describing fluid flow in porous media, it is rarely used in this form in practical engineering calculations. Instead, oil compressibility is usually assumed to be constant, allowing the defining equation to be integrated over some pressure range of interest. Thus, the oil compressibility in the resulting equations should be regarded as a weighted average value over the pressure range of integration.

The three distinct applications for oil compressibility in reservoir engineering are 1) instantaneous or tangent values from the defining equation, 2) extension of fluid properties from values at the bubblepoint pressure to higher pressures of interest, and 3) material balance calculations that require values starting at initial reservoir pressure. Each of these three applications requires a different approach to calculating oil compressibility from laboratory data and in developing correlations.

The differences among the values required in these three applications can as high as twenty-five percent. Most published correlations do not indicate the particular application to which the proposed correlation applies.

A correlation equation for oil compressibility has been developed using over 3,500 lines of data from 369 laboratory studies. This correlation equation gives the average compressibility between the bubble point pressure and some higher pressure of interest. Equations to calculate appropriate values of compressibility for the other two applications are presented.
Removal of Debris from Deepwater Wellbores Using Vectored Annulus Cleaning System Reduces Problems and Saves Rig Time
Authors: Connell P. , Haughton D. B.
Published: December 2007

Debris management is a major concern for producers. Wellbore debris is responsible for many of the problems and much of the extra cost associated with extreme water depths and highly deviated holes. This paper discusses procedures and tool systems developed to optimize the efficiencies and economics of debris removal. Issues pertinent to deepwater wellbore cleaning will be discussed, along with the problems associated with removal of debris caused by perforating, milling, etc. The authors will outline techniques for removal of this debris and discuss a tool system that is a workable solution for these problems.

This paper will focus on the use of a Vectored Annulus Cleaning System to remove debris from areas of the wellbore that have normally proven very difficult. The system has been shown to be effective in removing debris from problem areas such as above liner tops or where casing size changes, areas with a loss of annular velocity, and inwells with little to no circulation. Case histories from the Gulf of Mexico and the North Sea will demonstrate how this technology has reduced problems of debris removal while saving rig time by eliminating trips.
Relative Permeability Hysteresis: Trapping Models and Application to Geological CO2 Sequestration
Authors: Spiteri E. J. , Juanes R. , Blunt M. J. , Orr F. M.
Published: December 2007

The complex physics of multiphase flow in porous media are usually modeled at the field scale using Darcy-type formulations. The key descriptors of such models are the relative permeabilities to each of the flowing phases. It is well known that, whenever the fluid saturations undergo a cyclic process, relative permeabilities display hysteresis effects.

In this paper we investigate hysteresis in the relative permeability of the hydrocarbon phase in a two-phase system. We propose a new model of trapping and waterflood relative permeability, which is applicable for the entire range of rock wettability conditions. The proposed formulation overcomes some of the limitations of existing trapping and relative permeability models. The new model is validated by means of pore-network simulation of primary drainage and waterflooding. We study the dependence of trapped (residual) hydrocarbon saturation and waterflood relative permeability on several fluid/rock properties, most notably the wettability and the initial water saturation.

The relevance of relative permeability hysteresis is then evaluated for modeling geological CO2 sequestration processes. Here we concentrate on CO2 injection in saline aquifers. In this setting, the CO2 is the nonwetting phase, and trapping of the CO2 is an essential mechanism after the injection phase, during the lateral and upward migration of the CO2 plume. We demonstrate the importance of accounting for CO2 trapping in the relative permeability model for predicting the distribution and mobility of CO2 in the formation. We conclude that a proper treatment of the nonwetting phase trapping leads to a higher estimate of the amount of CO2 that it is safe to inject.
The Use of Dimensionless Scaling Methods to Predict Field-Scale Tertiary EOR Project Performance
Authors: Simmons J. F. , Falls A. H.
Published: December 2007

The scaling approach presented in this paper has proven effective in modeling the performance of West Texas CO2 projects. This methodology was developed, and has been utilized successfully, to model the performance of the Wasson Denver Unit, which is the world's largest miscible CO2 project. Methods are described for predicting injection and production rates for tertiary enhanced oil recovery (EOR) projects using dimensionless recovery curves. The primary use of the program has been for miscible CO2 flooding; however, the same methods could also be used for other tertiary processes such as alkaline surfactant flooding.

This program, which has been titled "DUSCALE," is based upon dimensionless recovery curves that can be either simulation-based or derived from analog actual project performance. One key attribute of the program is the ability to model the changes in reservoir processing rate that are common in these projects. Such variation impacts both the performance of the underlying waterflood and also the performance of the tertiary EOR project. Underlying waterflood production is forecasted using a throughput-based regression fit of historical pattern-level performance. Predictions are generated for all injected and produced fluids (oil, hydrocarbon gas, NGL yield, water, and CO2).

The program has also proven valuable as a surveillance tool for comparing actual versus predicted performance of an EOR project at the pattern level. Such analysis has identified project areas with good performance that are worthy of larger injected CO2 slugs, and also patterns within projects that are not meeting tertiary recovery targets. The ability to adjust expectations for processing rate variations is critical in such evaluations, as accelerated waterflood production (due to improved reservoir throughput during a CO2 project) can be incorrectly attributed to the CO2 displacement process.

This paper presents the methodology employed in the program and demonstrates, with examples from the Permian Basin, how the program can be used to generate forecasts for field-scale EOR projects. Examples highlighting surveillance applications are also be included.
Field Results: Effect of Proppant Strength and Sieve Distribution Upon Well Productivity
Authors: Huckabee P. , Vincent M. C. , Foreman J. , Spivey J. P.
Published: December 2007

Development of the Pinedale Anticline (PDA) of western Wyoming is proceeding at a rapid pace. During the past five years, approximately 500 million pounds of proppant have been placed into nearly 200 new wells. Despite this high activity level, no clear consensus has emerged from the various operators as to the optimal stimulation design. Proppant costs range from less than 20% to greater than 65% of the stimulation service company ticket dependent on proppant type selected. For one operator, proppant costs represent approximately 30% of the total completion cost and are a target for cost reduction efforts. These cost reduction efforts must be balanced with the economic value of proppant conductivity and its relationship with effective fracture halflength.

This paper summarizes results from a field trial that was implemented to investigate the effect of proppant selection upon productivity from low-permeability (0.0006 – 0.015 md) formations of the Pinedale Anticline. This study compares the production from 452 fracture treatments in 30 new wells completed by Shell Rocky Mountain Production during the past three years. Production logs are used to compare the productivity of fractures propped with 20/40 sand, 20/40 resincoated sand, 20/40 economy light-weight ceramic, broadsieved intermediate strength, and 20/40 intermediate strength proppants. The results from this study are believed to be the first published field comparison of broadly-sieved and tightlysieved ceramics.

This trial predominantly maintained a consistent stimulation strategy to reduce complexity and uncertainty in the analysis of the proppant selection evaluation. Proppant selection was varied by stage dependent on depth and geologic intervals to provide reliable offset comparisons. Results are categorized by geologic interval to reduce uncertainties from variations in reservoir quality and pressure differentials to more accurately assess the impact of altering proppant type. Economic analyses are presented to illustrate the most cost effective products to incorporate into each fracture treatment. Actual field results are compared to model predictions and laboratory results to determine whether proppant strength and sieve distribution affect production in a predictable manner.
Active Slug Management
Authors: Slupphaug O. , Hole H. , Bjune B.
Published: December 2007

Slug flow, or instabilities, in multiphase wells and -pipelines feeding oil- and gas processing facilities may cause operational challenges related to avoiding unplanned partial- or complete shutdowns, satisfying flaring volumes, managing sand production, maintaining on-spec production, proving of fiscal meters, etc. Conventional approaches to manage slug flow in wells and pipelines include: choking the well/pipeline, increasing gas lift rate(s), and/or providing overcapacity to accommodate the slugs that are produced erratically. All these conventional approaches imply inefficient production or expensive over-design. In this paper, a different—from choking and use of gas lift for stabilization—non-intrusive approach to slug management in wells and pipelines is presented. However, it will typically be complementary to other means, like choking and excessive use of gas lift, of handling slug flow challenges. The approach also applies to handling challenges related to oscillations and transients in the total production system, not only in the wells and pipelines. It may be interpreted as slug management from a practical dynamical systems point-of-view. It has emerged as a result of providing oil- and gas field operators with services and solutions with respect to slug management since the late 1990's. The associated base of experience includes hands-on experience from approximately 20 fields—mainly in the North Sea. The approach consists of solutions for automatic control, or, active feedback control, of well(s)/pipeline(s) and associated separators as well as services for generic handling of oscillations/instabilities including control strategy selection and -tuning. Field results from application of the approach are included. The experience gathered during these years supports that an integrated view of the dynamics of well(s)/pipeline(s) and the processing facilities is required in order to sort out proper activities and means for improving the slug management. Furthermore, it is important that this view is based on an analysis of relevant historical data. The analysis phase should involve key personnel from operations like senior operators, production-, and process engineers. It is our experience that operators who, as part of their slug management strategy, include an approach with characteristics similar to the ones summarized above, will improve operations significantly in an efficient and sustainable manner.
An Electrical Analog Facility for Hydrocarbon Reservoirs
Authors: Worthington P. F.
Published: December 2007

A user-friendly type chart has been constructed as an aid to the petrophysical evaluation of water saturation. It provides a basis for the inter-reservoir comparison of electrical character in terms of adherence to, or departures from, Archie conditions in the presence of significant shaliness or low formation-water salinity. The chart describes a continuum of electrical behavior for both water and hydrocarbon zones. In this respect, it is a generalization of earlier approaches that were necessarily restricted to the water zone. This extension is achieved by adopting a generalized geometric factor, the ratio of formation resistivity to water resistivity, regardless of the degree of hydrocarbon saturation. The type chart relates normalized geometric factor to formation-water conductivity, "shale" conductivity and (irreducible) water saturation. The approach has been benchmarked using data from comprehensively studied reservoirs. The application of the method is described with particular reference to rock types, scale effects, core sampling levels and net reservoir criteria. The use of the type charts is illustrated for reservoir units that show different levels of non-Archie effects. The deliverables include reservoir classification, for interpretation strategy and optimum core-data acquisition, and reservoir characterization in terms of analog porosity and saturation exponents. The principal benefit is a reduction in the uncertainty associated with the well-log analysis of water saturation at an early stage in the appraisal/development process when adequate characterizing data are not available.
A New Approach to Information Discovery—Geography Really Does Matter
Authors: Palkowsky B.
Published: December 2007

The energy industry is under constant pressure to improve performance measures and knowledge worker productivity. The demand to adequately replace reserves and increase profitability is constantly there despite the decline in field sizes, decreased well production and escalating depletion rates. The costly investments needed to build reserves utilizing the rapidly declining workforce demands further adoption of new technology. Innovative technology has always played a key role in making knowledge workers more productive by reducing workflow cycle time and improving reservoir prediction accuracy.
Reservoir Drilling Fluids—Designing for Challenging Wells in a Remote Location
Authors: Bradshaw R. , Hodge R. , Wolf N. O. , Knox D. , Hudson C. , Svoboda C.
Published: December 2007

The Belanak A platform is situated in the Natuna Sea region of Indonesia. The reservoir sections are high temperature (315°F BHST), and the openhole sections were planned to be between 3500 and 4500 ft horizontal, some with tortuous well paths required to meet the target. In order to ensure excellent drilling performance and optimum protection of the producing formation, a formate-based, low-solids reservoir drilling fluid was selected – the first time such a system had been used in Indonesia.

In this paper, the authors detail the design and successful application of the unique reservoir drill-in fluid in the demanding and remote well.
Drilling and Completing Wells Uphill
Authors: Prince P. , Tarmidi R. , Hou T. W.
Published: December 2007

In the work environment of continuous improvement as a method to reduce both drilling and production costs, alternative means are required to attain objectives which have previously been deemed unachievable. The introduction of new tools and technologies has enabled increasingly challenging wellpaths to be drilled and completed. Trajectories labeled as undrillable even a few short years ago are now being realized.

The high cost and environmental concerns associated with offshore installations and the resultant requirement for drilling multiple wells from a common facility, has been a significant driver in the field of extended reach drilling to drain reservoirs with significant step-out. Sub-surface geological issues and wells with multiple targets have resulted in complex 3D well trajectories such as ‘pregnant lady’, ‘snake’ and ‘dragon’ wells.

Within the above context, Brunei Shell Petroleum (BSP) has identified that by drilling ‘fishhook’ shape wells, whereby a large section of the wellpath is drilled and completed at an inclination greater than 90°, significant savings in both drilling and production costs can be achieved. This is a case study of such a well drilled in mid 2004, whereby some 875m, or 35% of the total well trajectory was drilled at an inclination greater than 90°. The well also required 7" casing to be run and cemented to well TD, sand control in the form of Frac and Packs, and Expandable Sand Screens (ESS) run across three reservoir zones, with isolation between each zone.

Maximum inclination was 126.5°, and some 366m true vertical depth (TVD) reclaimed.
A Flow Assurance Study for a Satellite Crude-Oil System With Severe Emulsion
Authors: Tang Y. , Wong S.
Published: December 2007

This paper discusses a recently completed FEED and post-FEED flow assurance study for the development of two satellite crude oil producing systems in West Africa. A 33 km 24 in. trunkline will transport the satellite field production to the main field.

With a gas/liquid two-phase trunkline, terrain induced slugging required a slug catcher that was too big to be cost-effective. To mitigate the severe slugging problem, a gas/liquid separator was recommended at the inlet of the satellite manifold and the liquid surge volume could be completely eliminated. A 4 in. separate gas pipeline was adequate to avoid surge capacity requirements at the outlet.

The demulsifier becomes less effective at watercuts (WC) greater than 60% and the peak viscosity can be as high as 10,000 cp. The restricting factors are the maximum-allowable-operating-pressure (MAOP) of 46 bara for the pipeline startup. A two-step ramp-up schedule was recommended to keep the peak pressure to an acceptable level. A limited number of well VSDs (Variable Speed Drive for ESP wellhead control) are required based on the slower ramp-up scheme and production profile.

Some guidelines are given in this paper for managing emulsion crude oil system issues.
A Rigorous Compressible Streamline Formulation for Two- and Three-Phase Black-Oil Simulation
Authors: Cheng H. , Osako I. , Datta-Gupta A. , King M. J.
Published: December 2007

Streamline simulators have received increased attention in the petroleum industry because of their ability to effectively handle multimillion cell detailed geologic models and large simulation models. The efficiency of streamline simulation has relied primarily on the decoupling of the 3-D saturation equation into 1-D equations along streamlines using the streamline time of flight as the spatial coordinate. Until now, this decoupling has been strictly valid for incompressible flow. Applications to compressible flow have generally lacked strong theoretical foundations and for the most part yielded mixed or unsatisfactory results.

In this paper for the first time we generalize streamline models to compressible flow using a rigorous formulation while retaining much of its favorable characteristics. Our new formulation is based on three major elements and requires only minor modifications to existing streamline models. First, we introduce an ‘effective density’ for the total fluids along the streamlines. This density captures the changes in the fluid volume with pressure and can be conveniently and efficiently traced along streamlines. Thus, we simultaneously compute time of flight and volume changes along streamlines. Second, we incorporate a density-dependent source term in the streamline saturation equation to account for compressibility effects. Third, the effective density, fluid volumes and the time-of-flight information are used to incorporate cross-streamline effects via pressure updates and remapping of saturations. Our proposed approach preserves the 1-D nature of the saturation calculations and all the associated advantages of the streamline approach. The saturation calculations are fully decoupled from the underlying grid and can be carried out using large time steps without grid-based stability limits.

We demonstrate the validity and practical utility of our approach using synthetic and field examples and comparison with both commercial finite difference and streamline simulators. The synthetic examples involve waterflooding in a ¼-five spot pattern under undersaturated conditions and also three phase flow with both free and solution gas. Our results show close agreement with the finite difference simulator in terms of water-oil and gas-oil ratio histories for an extended period of time. The field example is from a highly heterogeneous carbonate reservoir in West Texas and includes multiple patterns consisting of 11 injectors, 31 producers and over 30 years of production history. Our proposed formulation results in significant improvement in performance prediction over current commercial streamline simulators.
Strength Analysis of Liners for Horizontal Wells
Authors: Plácido J. C. R. , Pasqualino I. P. , Fonseca C. E.
Published: December 2007

Liners with slots or holes are broadly employed to increase the production of horizontal wells. However, as these openings at the casing wall can reduce its strength under mechanical loading, such as radial compression, axial tension and bending, the structural response of the liners must be properly studied. A numerical and experimental procedure has been developed to optimize liner geometries. Different liner conceptions, with varied arrangements of slots and holes have been proposed to study its structural response under mechanical loading. The proposed conceptions were analyzed with the aid of nonlinear three dimensional finite element models incorporating metal plasticity, contact behavior and large rotations. Experimental tests of liners with slots under radial compression and bending were accomplished. The finite element models were calibrated through the correlation of experimental and numerical results.
Coal Failure and Consequences for Coalbed Methane Wells
Authors: Palmer I. , Moschovidis Z. , Cameron J.
Published: December 2007

We provide a summary of coal failure during the life of a typical coalbed methane (CBM) well, and some consequences for the CBM industry. Because coals are weak in general, these consequences are often important, and can have a significant impact on drilling, completion, and production of CBM wells.

Failure during drilling: horizontal wells are the preferred completion in the Arkoma basin, for instance. Drilling horizontal wells is sometimes hindered by hole collapse, especially when drilling underbalanced, or drilling through a depleted coal. We demonstrate the relative importance of this by comparing drilling stability in coals of various ranks and depths.

Failure during hydraulic fracturing: in weak coals the increased pore pressure around a fracture can cause shear failure. The likelihood of shear failure is charted against coal rank, for given in situ stress, and fracturing pressure. When coal fails in shear, coal fines are produced in the reservoir, as has been demonstrated in the lab. The creation and movement of such fines can reduce the coal permeability, and the frac conductivity. However, dilatancy accompanying shear failure can also lead to permeability increases.

Failure during production: when a CBM well is put on production, by applying a drawdown, the lowering of BHFP can cause failure of the coal (or collapse of a horizontal openhole) if it is weak enough. The critical drawdown for failure and fines production can be predicted by using advanced technology borrowed from the sand production arena. We can characterize the probability of failure by coal rank, drawdown, depletion, as well as other parameters like in situ stress.

Careful assessment of the likelihood of coal failure during drilling, fracturing, or production, as a function of coal rank and in situ stress, can lead to mitigating efforts to avoid the bad consequences. For example, applying a smaller drawdown in a producing CBM well may prevent or defer failure in weak coals and mitigate fines plugging of the formation and fracture, fill in the wellbore, and pump or compressor problems.
Evaluation of Unconventional Resource Plays
Authors: Haskett W. J. , Brown P. J.
Published: December 2007

Making sound business decisions in one of the hottest domestic exploration plays, unconventional gas, offers a set of challenges not usually encountered with more traditional opportunities. Unlike with standard prospect and conventional play risk analysis, geologic chance is not a major issue, and estimates of initial production, decline rates, mechanical efficiency, and success planning dominate the analysis rather than traditional volumetric determinations. The valuation and assessment of unconventional or "continuous resource" opportunities is not feasible using traditional probabilistic, volumetric-based methods. A fully stochastic business, value-chain model is the best way to assess the potential of an unconventional play. Such an evaluation method allows for multi-disciplinary and cost input that affords decision makers with the appropriate data to make good decisions.

The boundaries of unconventional reservoirs extend well beyond the limits of most individual acreage holdings. As such, the recommendations of Schmoker and others to base the full resource availability on a cell or single well drainage area should be embraced as a starting point.

Resource uncertainty is handled by a continuum of well size distributions arranged to form an EUR Envelope. Volumes are only part of the equation, however. Uncertainty in the production profile must be taken into account, with variations in initial production, decline rate, and hyperbolic exponent figuring prominently in the final assessment of profitability.

There are four main stages in the exploitation of unconventional opportunities: Exploration, Evaluation, Delineation, and Development. Proper assessment, including identification and management of downside risk, requires a decision-focused, integrated, multi-discipline evaluation process through the four stages.

Unconventional plays use an initial number of wells to test the viability of a play and stimulation technology/methods. These pilot programs can be optimized, for number of wells, and company risk tolerance. Pilot Effectiveness is the (measurable) probability of the pilot program providing truthful results given the small number of test wells modeled.

Output from the proposed stochastic evaluation method include both single economic and product-based metrics in cumulative probability curves, as well as time series output in both aggregate and pathway forms. A thorough understanding of results analysis, Value of Information, and decision options is encouraged in order to take full benefit of the stochastic assessment method.
A New Approach for Capitalizing on Continuous Downhole Pressure Data
Authors: Viberti D. , Verga F. , Delbosco P.
Published: December 2007

Intelligent completions typically include permanent downhole gauges (PDG's) for continuous, real-time pressure and temperature monitoring. If adequately applied, such new technologies should allow anticipation of oil production and increase of final recovery with respect to traditional completions. In fact, pressure data collected from PDG's represent an essential information for understanding the dynamic behavior of the field and for reservoir surveillance. The potential drawback is that the number of data collected by PDG's can grow enormously, making it very difficult, if not impossible, to handle the entire pressure history as it was recorded. As a consequence it might often be necessary to reduce the pressure measurements to a manageable size, though without losing any potential information contained in the recorded data.

As extensively reported in the literature, long-term data might be subject to different kinds of errors and noise, and not be representative of the real system response. Before the data can be used for interpretation purposes, especially if pressure derivatives are to be calculated (for instance, in well test analysis), an adequate filtering process should be applied. Multi-step procedures based on the wavelet analysis were presented in the literature for processing and interpreting longterm pressure data from PDG's. In this paper an improved approach largely based on the wavelet algorithms is proposed and discussed for the treatment of pressure data.

All the steps of the procedure, namely outliers removal, denoising, transient identification, and data reduction were applied both to synthetic and real pressure recordings. Results indicated that the application of the proposed approach allows identification of the actual reservoir response and subsequent interpretation of pressure data for an effective characterization of the reservoir behavior even from very disturbed signals.
Mapping Fluid Flow in a Reservoir Using Tiltmeter-Based Surface-Deformation Measurements
Authors: Du J. , Brissenden S. J. , McGillivray P. , Bourne S. , Hofstra P. , Davis E. J. , Roadarmel W. H. , Wolhart S. L. , Wright C. A.
Published: December 2007

Surface deformation measurements have been used for years in oilfields to monitor production, waterflooding, waste injection, steam flooding, and Cyclic Steam Stimulation (CSS). They have been proven to be a very effective way to monitor the field operations and save money for operators wishing to avoid unwanted surface breeches, casing failures and excessive subsidence due to production. This paper demonstrates that more information can be extracted from surface deformation measurements by inverting the surface deformation for the volumetric deformation at the reservoir level, so the areal distribution of volumetric deformation can be identified. First, a poroelastic model is presented to calculate the deformation due to the volumetric change in the reservoir. Then, a linear geophysical model is formulated to invert for the reservoir volumetric deformation from the measured surface deformation (or tilt). Constraints are added into the procedure as necessary to better resolve the inversion problem. After each inversion, the theoretical surface deformation (displacement, tilt, reservoir compaction and volumetric strain) can be calculated from the inverted volumetric deformation distribution which best fits the measured deformation data (or tilt) at the surface. The technique of mapping fluid flow using surface deformation was applied to real data from a cyclic steam injection project.
Assessment and Development of the Dry Horseshoe Canyon CBM Play in Canada
Authors: Bastian P. A. , Wirth O. F. R. , Wang L. , Voneiff G. W.
Published: December 2007

This paper discusses how the Horseshoe Canyon coalbed methane (CBM) play in Western Canada was converted from an under-explored, non-commercial resource to a major commercial play through the application and modification of technology and analysis techniques from other basins, and how this play is being developed today. As of December 2004, production from the Horseshoe Canyon CBM play is estimated to be over 100 MMscfd of gas, with future production expected to grow significantly. The first commercial developments were completed in 2003 and 2004, and drilling is increasing and expected to exceed 3,000 wells per year in 2005.1

The Horseshoe Canyon CBM play covers a large geographic area of 200 miles by 50 miles, and exists in a large, complex vertical section with numerous coal, sand, silt, shale and mudstone layers. In addition, the play is naturally under-pressured, and the coal beds are mostly dry. Because of these complex and unique characteristics, assessment of commercial viability and development optimization can be confusing and only applicable over small parts of the play. MGV Energy, Inc. (a wholly-owned subsidiary of Ft. Worth-based Quicksilver Resources, Inc.) and its initial joint venture (JV) partner, PanCanadian Petroleum Limited (now EnCana Corp.), discovered the techniques to achieve commerciality and pioneered many of the practices used by industry today for Horseshoe Canyon CBM development. In this paper, we discuss identification of the reservoir opportunity, including data acquisition and analysis. We describe geologic and reservoir models, and production forecasting methods. We also cover completion and production practices, spacing optimization and reserves estimation procedures.
Streamline Simulation of Four-Phase WAG Processes
Authors: Bhambri P. , Mohanty K. K.
Published: December 2007

Miscible or near-miscible water-alternating-gas (WAG) flooding is an attaractive process for medium viscosity (30-300 cp) oils if solvents are available. Four fluid phases can develop in these processes. Very few reservoir simulators and none of the published streamline simulators can handle four fluid phases. In this work, we have developed a four-phase streamline module that works with an existing finite-difference simulator to study gas or WAG injections in medium viscosity reservoirs. 2-D and 3-D simulations of WAG injections in quarter five-spot models have been demonstrated using this simulator. WAG injection simulation of the reservoir oil indicates that four phases exist near the gas-oil displacement front. The second liquid phase (or the third hydrocarbon phase) is present in many grid blocks under the conditions studied. WAG injection improves the sweep over the single slug solvent injection. For the cases studied, the sweep efficiency increases with the WAG ratio, but this result cannot be generalized. Reservoir hetrogeneity also affects the sweep. Gravity override is observed in WAG simulations with the vertical (X-Z) crossection. Oil recovery is low in the lower part of the reservoir. Horizontal production wells affect the fluid flow and thus the sweep of the reservoirs.
Optimizing the Subsurface Work Environment of the Future
Authors: Reece C. A. , Catron R. E. , Hammond R. D. , Schmidtke E. A.
Published: December 2007

Over its history, ExxonMobil* has pursued a variety of initiatives to improve its subsurface work environment and capabilities. A recent multi-disciplinary and multi-company effort identified a step change improvement opportunity in the subsurface work environment with:

increased integration across technical disciplines and functional companies, general interest oversight of ongoing initiatives to ensure that all efforts are aligned with a desired end state while capturing efficiencies, and improvements in foundational areas such as data management concurrent with the development of new capabilities.

This paper shares ExxonMobil's vision for the Subsurface Work Environment of the Future and critical success factors to achieve it. ExxonMobil's commitment to global standards and a global functional organization provides a unique framework upon which to integrate and leverage work processes, tools and technology across its upstream companies and technical disciplines. This vision is based on business-driven affordability, proprietary and commercial technology and a systems management approach to the subsurface business.
Injectivity Profiling in Horizontal Wells Through Distributed Temperature Monitoring
Authors: Pimenov V. , Brown G. , Tertychnyi V. , Shandrygin A. , Popov Y.
Published: December 2007

Downhole permanent monitoring sensors offer unique options for continuous evaluating flow regimes, completion integrity, formation properties, flow assurance effectiveness and optimal production/injection operations. The use of temperature data for vertical injection wells has been widely applied in practice and has been thoroughly discussed in literature. The problems occur for Distributed Temperature Sensors (DTS) installed in horizontal well due to small variations of geothermal temperature along the wellbore. Unlike the conventional gauges, DTS data are acquired in both temporal and spatial dimensions that exploit the great potential for real-time operation optimization.

We present an interpretation technique for analysis of temperature profiles recorded with fiber optic distributed temperature sensor (DTS) in horizontal water injectors. Simple semi analytical models were developed for simulating mass and heat transfer in horizontal well and collector during injection and warm back. Two inversion procedures based on these models were developed allowing calculation of injectivity profile from temperature profiles recorded during injection and warm-back. These procedures were successfully validated on CFD numerical model and tested on field data.