bluuebunny/crossref_metadata_2025 huggingface dataset:
Geomechanical and Decision Analyses for Mitigating Compaction-Related Casing Damage
Authors: Bruno Michael S.
Published: December 2007

Reservoir compaction and its associated bedding plane slip and overburden shear have induced damage to hundreds of wells in oil and gas fields throughout the world. Critical casing damage mechanisms observed in a variety of structural settings include overburden shear damage on localized horizontal planes, shearing at the top of production and injection intervals, and compression and buckling damage within the production interval, primarily around perforations.

Analytical solutions are readily available to estimate compaction, subsidence, and casing damage risks. These should be applied as initial screening tools at an early stage in reservoir development planning. They also can be applied to estimate relative risks for various well locations and trajectories.

Geomechanical models of increasing complexity, including 2D and 3D finite element type techniques, have been used with good success to assess formation deformation and casing damage risks in several reservoirs and are described herein. Three-dimensional geomechanical models at the wellbore scale are required to evaluate shearing deformation on specific well designs and are used to assess damage mitigation effectiveness for varying completion strategies.

An economic decision tree model is applied to compare the costs and benefits of alternative well designs while taking into account inherent uncertainties in model input data, the well's damage location, and the effectiveness of various mitigation strategies. In some instances, the appropriate action is not to change the completion design, but simply to accept damage risk.
A Laboratory Study of the Effects of CO2 Injection Sequence on Tertiary Oil Recovery
Authors: Wang George C. , Locke C. David
Published: December 2007

The major reason that CO2 stands out as a fluid displacement agent for enhanced oil recovery is because of the adaptability and relatively low cost of CO2 compared with other chemical flooding agents. CO2 miscible displacement could be achieved for a wide spectrum of reservoir oils through an extraction/vaporization process. Even under immiscible reservoir conditions, incremental oil recovery still can be obtained by simple viscosity reduction and swelling of crude oil. Among other desirable properties of CO2 is its high density. At typical reservoir conditions, CO2 is nearly as heavy as reservoir oil; thus, the problem of overriding common to most gas injecting systems could be minimized greatly.

In spite of all the advantages of CO2 process, it inherits the disadvantage of high mobility ratio so that the CO2 has a great tendency to channel through the oil, bypassing much of the oil in the reservoir. To alleviate the difficulties, a technique consisting of alternately injecting small CO2 and water slugs has been applied in field tests.1 The injected water interferes with the flow of CO2 to minimize the chance of premature CO2 breakthrough.

Another technique, called "programmed slug," has long been applied in polymer flooding to prevent deleterious effects of viscous fingering. More recently, Claridge2 has developed a method for designing graded banks for both polymer and miscible flooding. His study indicates that the use of a graded slug often results in improvement of oil recovery and/or economic attractiveness.
Quantitative Analysis of Drag Reduction in Horizontal Slug Flow
Authors: Daas M. , Kang C. , Jepson W.P.
Published: December 2007

Calculations have been made to predict the components of pressure drop in slug flow. This analysis is aimed at understanding, in a quantitative manner, the contributions of both frictional and accelerational components to total pressure drop in horizontal slug flow and the effect of drag reducing agents (DRAs) on each component. Experimental results were in good agreement with predicted values.

The DRA used in this study was effective in reducing both components of the pressure drop. The accelerational component was found to be dominant and formed more than 80% of the total pressure drop. It increased dramatically with increasing superficial gas velocity. With the addition of 20 ppm DRA, the accelerational and frictional components were noticed to decrease by a factor of 70%. At DRA concentration of 50 ppm, they decreased by a factor of 80%. Total drag reduction was found to generally decrease at higher superficial gas velocities.

In sharp contrast with expectations, the drag reduction was recovered mainly from the accelerational component, indicating that the DRA worked not only in the buffer zone but also in the mixing zone in the slug body. The accelerational drag reduction reached values as high as 89% of total drag reduction.
A Comprehensive Wellbore Steam/Water Flow Model for Steam Injection and Geothermal Applications
Authors: Ali S. M. Farouq
Published: December 2007

A comprehensive mathematical model was developed to simulate the downward or upward flow of a steam/water mixture in a well. Comparisons of model predictions with actual field data for both steam injection for oil recovery and geothermal production showed the validity of the model.

The proposed model is based on mass and momentum balances in the wellbore and on heat balance in the wellbore and the surrounding media. Unlike the previous models, the pressure calculation accounts for slip and the prevailing flow regime, based on noted correlations. Furthermore, heat loss to the surrounding formations is treated rigorously. The overall heat transfer coefficient involved permits the consideration of a variety of well completions.

The model was employed for a series of tests to evaluate the effects of the injection pressure, injection rate, time, and well completion on the downhole steam pressure and quality. It was found that the slip concept and the flow regime are essential elements in wellbore steam/water flow calculations. Pressure drop was found to increase with a decrease in the injection pressure, as also with more obvious parameters. An increase in the injection pressure or tubing size and/or a decrease in the injection rate led to a decrease in steam quality at a given depth.
Pressure Buildup Analysis for a Well Produced at Constant Bottomhole Pressure
Authors: Uraiet A.A. , Rajagopal Raghavan
Published: December 2007

This paper presents procedures to analyze the pressure buildup behavior at a well produced at a constant pressure. Introduction Pressure buildup analyses generally assume that the well produces either at a constant surface rate or at a series of discrete constant rates prior to shut-in. To our knowledge, only Clegg1 has attempted to analyze by conventional semilog techniques2 the buildup behavior of a well produced at a constant wellbore pressure. The lack of research efforts in this area of pressure analysis is not due to the lack of the importance of the problem or the lack of application to petroleum engineering; it is mainly due to the difficulty of obtaining a simple analytical expression to describe the bottomhole pressure buildup behavior at a well, subsequent to production at a constant pressure. The mathematical problem stems from the difficulty of handling the change in the inner boundary condition when the flowing well is shutin - i.e., changing the Dirichlet condition to a Neumann condition. This problem does not occur in the constant-flow-rate case, since the pressure buildup equations can be obtained directly by using the principle of superposition. In fact, the requirement that a well be produced at a constant rate prior to shut-in is imposed by theoretical considerations.

Our objective is to suggest simple procedures to analyze the pressure buildup behavior at a well producing at a constant flowing pressure similar to those used for the constant-flow-rate case.

To date, this type of problem usually is solved by treating the continuous change in rate as a sequence of discrete (step-function) rate changes and then applying the principle of superposition.4,5 This is a tedious and cumbersome procedure, and data often are not available for this type of analysis.

The approach taken here is to follow a generalized procedure similar to the one suggested by Ramey and Cobb6 for the constant-flow-rate case. We obtain pressure buildup data, graph data along conventional lines, and seek simple interpretive rules to analyze these data. We avoid restrictions on producing time which commonly are employed in the classic developments2,3 and do not require that the well be produced at a constant rate prior to shut-in.

This work is a study of pressure behavior during the buildup period. It includes the examination of the effects of producing time prior to buildup, the nature of the outer boundary condition (closed and constant-pressure drive), damage (or stimulation) around the well, and well bore storage. It also includes the analysis of interference data due to the closing in of the producing well.

All the results in this study were obtained by a numerical (finite difference) model.

p. 1813–1824
Pressure Buildup for Wells Produced at a Constant Pressure
Authors: Ehlig-Economides C. A. , Ramey H. J.
Published: December 2007

Conventional well test analysis has been developed primarily for production at a constant flow rate. However, there are several common reservoir production conditions which result in flow at a constant pressure instead of a constant rate. In the field, wells are produced at constant pressure when fluids flow into a constant-pressure separator and during the rate decline period of reservoir depletion. In geothermal reservoirs, produced fluids may drive a backpressured turbine. Open wells, including artesian water wells, flow at constant atmospheric pressure.

Most of the existing methods for pressure buildup analysis of wells with a constant-pressure flow history are empirical. Few are based on sound theory. Hence, there is a need for a thorough treatment of pressure buildup behavior following constant-pressure production.

In this work, the method of superposition of continuously changing rates was used to generate an exact solution for pressure buildup following constant-pressure flow. The method is general. Storage and skin effects were incorporated into the theory, and both bounded and unbounded reservoirs were considered. Buildup solutions were graphed using conventional techniques for analysis. Horner's method for plotting buildup data after a variable-rate flow was found to be accurate in a majority of cases. Also, the method by Matthews et al. for determining the average reservoir pressure in a closed system was determined to be correct for buildup following constant-pressure flow.
Enhanced Iterative Formation Evaluation of El Tordillo Field, San Jorge Basin, Argentina: Using Electrofacies and Production Prediction Index Determination
Authors: Stinco L.P. , Elphick R.Y. , Moore W.R.
Published: December 2007

Formation evaluation, electrofacies, and production prediction index determination based on inductive and deductive methodologies were completed in El Tordillo field, north flank of the San Jorge basin, Argentina. The applied methodology consisted of a number of steps, including the following: editing and normalization of the log data; modeling of the deep resistivity; electrofacies determination; standard log analysis; computing a production prediction index; and summations. Using cutting and core data, the 15 electrofacies determined were associated with the geological facies encountered within the field and on the rock types. Consequently, porosity/permeability relationships were established between the core data and the productive electrofacies. These relationships permit computing permeability from the computed effective porosity. A production prediction index was derived from the computed results and correlated well with existing production data. Zones of possible bypassed production were identified, and some tested successfully. Finally, summations were used as input for original-oil-in-place estimation, geological modeling, and numerical simulation.
4D Seismic Monitoring of Water Influx at Bay Marchand: The Practical Use of 4D in an Imperfect World
Authors: Behrens Ronald , Condon Patrick , Haworth William , Bergeron Mark , Wang Zhijing , Ecker Christine
Published: December 2007

Many waterflooded or aquifer influx reservoirs are old or marginal and thus do not have ideal data conditions, either historic or current, for 4D seismic. We modeled the synthetic seismic response for the 7100 Sand in the Bay Marchand field and found it suitable for 4D. To determine the noise level in modeling, we derived relations for calculating the appropriate level of noise from differences in the field data. We also developed relations between measured noise and the quantitativeness of calculated saturation changes. These methods, as applied to the Bay Marchand, showed that useful saturation predictions could be made from the seismic data shot 30 years after initial production with a recent, nonexclusive survey. From these data, both downdip and updip wells were drilled successfully.

Multiple seismic surveys over time that were not intentionally designed for 4D evaluation can be used for imaging fluid and pressure changes and locating bypassed reserves. Bay Marchand is a mature Gulf of Mexico field with a series of stacked reservoirs separated by shale. The first 3D seismic survey was acquired after first production, and the second seismic survey was a nonexclusive survey having very different acquisition parameters. These circumstances make interpreting 4D results difficult but not impossible. We were able to make a reasonable interpretation of the "A" fault block on the original data before cross-equalization (XEQ), although XEQ reduced the acquisition and processing differences between the cubes. We were able to identify areas of water influx and areas not yet invaded by water, even though we were prevented from following the typical steps in 4D. Reliability estimates were derived for estimates of saturation change as a function of signal-to-noise ratio and scatter in the rock physics relationships. This paper discusses these steps in contrasting the ideal case with Bay Marchand and shows where a 4D project can still be successful even with compromises forced by lack of early data or current budget.
Inflow Analysis and Optimization of Slotted Liners
Authors: Kaiser T. M. V. , Wilson S. , Venning L. A.
Published: December 2007

Slotted liners have been used for many years to provide sand control in many oil industry applications. They are commonly applied in western Canadian reservoirs that produce high-viscosity oil from horizontal wells with unconsolidated, high-permeability sands. Both primary and thermal applications are common, and the steam-assisted gravity drainage (SAGD) process1 is beginning to see widespread application in this area of the world. They are relatively inexpensive to manufacture and tolerant of installation loads, but historically they have not been able to offer the very small opening sizes of wire-wrap screens for controlling production of fine sands. However, recent advances in slot manufacturing methods provide slot openings that match and surpass the size and tolerance of wire-wrap screens. Furthermore, slotted liners offer an advantage in providing a variable slot density that can be used to optimize inflow or outflow distributions.

In the development of its south Bolney reservoir, Marathon Oil Canada and Noetic Engineering Inc. performed an analytical evaluation of inflow characteristics for a new generation of commercially available slots. Several interesting conclusions were reached, the most significant of which was that inflow resistance depends much more strongly on slot density than on open area. The inflow characterization was also used to optimize the slot-density distribution and to promote more uniform production throughout the well. The slotting was incorporated with a deformation-management system that controlled thermally induced loads, preventing compromise of sand-control characteristics.
Multiple Controls on Petroleum Biodegradation and Impact on Oil Quality
Authors: Wenger Lloyd M. , Davis Cara L. , Isaksen Gary H.
Published: December 2007

Biodegradation of oils in nature is important in reservoirs cooler than approximately 80°C. Oils from shallower, cooler reservoirs tend to be progressively more biodegraded than those in deeper, hotter reservoirs. Increasing levels of biodegradation generally cause a decline in oil quality, diminishing the producibility and value of the oil as API gravity and distillate yields decrease; in addition, viscosity, sulfur, asphaltene, metals, vacuum residua, and total acid numbers increase. For a specific hydrocarbon system (similar source type and level of maturity), general trends exist for oil-quality parameters vs. present-day reservoir temperatures of <80°C. However, other controls on biodegradation may also have significant effects, making predrill prediction of oil quality difficult in some areas.

It has long been observed that fresh, oxygenated waters in contact with reservoir oil can cause extensive aerobic biodegradation. More recently, it has been recognized that anaerobic sulfate-reducing and fermenting bacteria also can degrade petroleum. Highly saline formation waters may inhibit bacterial degradation and effectively shield oils from oil-quality deterioration. The timing of hydrocarbon charge(s) and the post-charge temperature history of the reservoir can have major effects on oil quality. Reservoirs undergoing current charging with hydrocarbons may overwhelm the ability of bacteria to degrade the oil, resulting in better-than-anticipated oil quality. Fresh charge to reservoirs containing previously degraded oil will upgrade oil quality. Calibrated methods of oil-quality risking, based on a detailed evaluation of reservoir charge and temperature history and local controls on biodegradation, need to be developed on a play and prospect basis.
A New Concept in Continuous-Flow Gas-Lift Design
Authors: Mach J. M. , Proano E. A. , Mukherjee H. , Brown K. E.
Published: December 2007

The importance of the differential pressure at the point of injection in continuous-flow gas-lift design is discussed. The role played by differential pressure in the selection of optimal flow in gas lift is also explained. It is shown that good wells with high productivity have continued increase in production as the differential pressure decreases. Weaker wells with low productivity, however, are less sensitive to the change in differential pressure. Also, a concept of error envelope surrounding the point of gas injection is presented. Suitable valve spacing in this error envelope is shown to offset any errors in locating the depth of injection caused by errors in the multiphase flow correlations or in the well productivity. The maximum valve spacing within the error envelope is shown to be directly proportional to the differential pressure. The smaller this differential pressure, the smaller the valve spacing.
Added Value of a Multiphase Flowmeter in Exploration Well Testing
Authors: Mus E. A. , Toskey E. D. , Bascoul S. J. F. , Norris R. J.
Published: December 2007

A multiphase flowmeter was used in addition to conventional surface well-test equipment during five deep offshore exploration drillstem tests. Several immediate benefits were derived. The cleanup phase was monitored, which improved control of the formation drawdown as well as the prediction of well eruption. The flow history was better quantified, which improved the pressure-transient analysis. The instantaneous flow-rate measurements shortened flow periods and accelerated the decision process, reducing the overall test duration. In general, the multiphase flow-meter enhanced operation flexibility, confidence in the information acquired, and accuracy of the results.
Considerations For Conducting Coiled-Tubing Well-Control Operations To Minimize Formation Impairment
Authors: Sas-Jaworsky Alexander , Ghalambor Ali
Published: December 2007

Coiled-tubing (CT) services are frequently used to conduct kill operations concentric to existing production tubulars. Kill operations are typically performed to effect a temporary hydrostatic balance of formation pressure at the exposed completion. Because CT well-control operations are conducted concentric to existing production tubulars, special attention to job design and implementation is critical to ensure proper placement of kill fluids within the wellbore to achieve the desired pressure balance and to minimize the potential of formation damage.

In those cases in which wellbore operations subsequent to the kill program are not intended to return the existing completion to active status, formation damage induced by the kill practice is typically of little consequence. However, when return of the existing completion to active status is desired, the well-control operation must be conducted with a complete understanding of the pressure balance and effect of kill fluid circulation on the completion. Many practices used in performing concentric-tubing well-control services lead to varying degrees of formation damage and impair completion flow performance.

This paper discusses typical damage mechanisms resulting from completed wellbore kill programs, along with the related formation damage consequences for these types of operations, alternative well-control kill processes with CT, and the potential for reducing formation damage with CT well-control processes. In addition, recommendations for planning and implementing CT-conveyed well-control programs within existing production tubulars are provided to guide the user in conducting well-control operations with minimal induced formation damage.
Semianalytical Modeling of Complex-Geometry Reservoirs
Authors: Zhao Gang , Thompson Leslie G.
Published: December 2007

Complex geometry reservoirs can be encountered in the field for a variety of depositional and tectonic processes. For example, fluvial depositional environments may produce interbranching channel reservoirs or reservoirs consisting of relatively high-permeability channels in communication with low-permeability splays.

This paper presents a general methodology for computing pressure responses and flow characteristics in complex geometry reservoirs. The proposed method consists of decomposing the original complex-geometry reservoir into a set of simple-geometry reservoirs, which interact with each other by transfer of fluid and equality of pressure over the regions where they are in hydraulic contact. Analytical solutions are written for each of the simple reservoir components in terms of the unknown pressures and fluxes at their boundaries, and the coupled systems are solved for the desired wellbore pressure responses.

The method of sources and sinks is used to compute the pressure response in the Laplace domain, and the results are inverted numerically with the Stehfest Inversion algorithm.1 We present fast, accurate methods of taking numerical Laplace transforms of the source/sink solutions that make the computations reasonably fast and efficient.

The proposed methodology can be extended to any system (infinite or bounded) in which the Laplace-space solution can be written easily in terms of integrals of real-space source/sink functions, including production at constant bottomhole pressure, wellbore storage effects, or naturally fractured systems. We demonstrate the applicability of the method by modeling branching channels and channel/splay systems.
Non-Darcy Flow Near Hydraulically Fractured Wells
Authors: Hagoort Jacques
Published: December 2007

In this work, we analyze the effect of non-Darcy flow near hydraulically fractured wells on well inflow performance. It is based on a dedicated numerical model of plane, steady-state flow of an incompressible fluid toward a vertically fractured well in the center of a circular reservoir. The results show that non-Darcy flow manifests itself as a positive skin factor, which is the product of a non-Darcy flow factor and the production rate, as is the case with nonfractured wells. An empirical relationship is presented that enables the estimation of the non-Darcy flow factor of fractured wells as a function of fracture length. Compared with nonfractured wells, hydraulic fractures will reduce the effect of non-Darcy flow in all practical situations. An intuitive approach to incorporate non-Darcy flow in the inflow performance relationship of fractured wells on the basis of total inflow area is a good first-order approximation.
Use of Permanent Resistivity and Transient-Pressure Measurement for Time-Lapse Saturation Mapping
Authors: Charara M. , Manin Y. , Bacquet C. , Delhomme J. P.
Published: December 2007

Optimization of hydrocarbon recovery requires information on the space and time behavior of the saturation of various fluids present in the reservoir. This is particularly true for oil fields under secondary recovery such as waterflooding, where an even reservoir sweep or zones of bypassed oil can be assessed by a proper description of the waterfront advance. Recently, permanent downhole electrodes have been deployed successfully in oil wells.

This technology allows the time variation of the electrode potentials to be interpreted in terms of changes in saturation within the formation. However, the depth of investigation of such measurements is limited. Time-lapse pressure transient is an independent source of information with a greater depth of investigation and, therefore, it provides an adequate complement to the permanent resistivity array measurement.

In this paper, we propose to use pressure buildup from repeated shut-in in association with the electrical measurements. After recalling analytical analogies in both types of measurements, we propose a quick-look method for interpreting the time-lapse pressure transients. We then compare the physical and practical advantages of each type of measurement and the domain of application of the two measurements with respect to fluid and reservoir properties. Finally, we propose an example showing the benefit obtained by coupling the two techniques.
Planning and Preparing for the First Subsea Field Test of a Full-Scale Dual-Gradient Drilling System
Authors: Schumacher J. P. , Dowell J. D. , Ribbeck L. R. , Eggemeyer J. C.
Published: December 2007

Dual-gradient drilling (DGD) is an emerging technology that will enable operators to drill in environments where mud weights are quite high and formation fracture pressures are quite low. This step-change technology will allow access to deepwater reserves and will fundamentally change the way deepwater wells are drilled.

This paper describes the planning and preparation for the world's first dual-gradient well in Green Canyon 136. Our objective was to deliver a functioning and proven DGD system for commercial application in deepwater environments. The dual-gradient system worked as designed, and 100% of all critical objectives were successfully met.
Today's Petroleum Engineering Graduate - Will He Meet Tomorrow's Challenge?
Authors: Sherborne John E.
Published: December 2007

Historically, engineers have been men whose function has been to analyze what is needed for solution of practical problems, to design or plan the needed systems. circuits, structures, or processes for this purpose and to predict their performance and cost. A hundred years ago as our national expansion began to accelerate, man was forced by lack of transportation and communication to work in much greater isolation than is now the case. The engineer was sought for the experience and judgment he could bring to a particular project - for the art he had developed - rather than for his scientific nowledge.

In discussing "Objectives of an Engineering Education," W. V. Houston illustrates the importance attached at that time to engineering experience, as well as the growing realization of the value of science to the engineer. In doing this he tells of the important part played by William Thomson in the laying of the Atlantic telegraph. Although the chief electrical engineer on the project was a man of considerable experience and of good reputation, he had no experience with cables as long as the one across the Atlantic. Thomson, who had virtually no practical experience, had, however, given considerable thought to electrical transmission and had pointed out the importance of capacitance and resistance in long conductors. Unfortunately, Thomson's findings were ignored, the engineer believing an extrapolation of his own experience preferable. The first cable thus laid at a cost approximating one million dollars was a failure and not until the advanced scientific findings of Thomson were employed was success achieved. This is not to discredit practical experience and the valuable wisdom it produced. Far from it! Rather, it is to indicate the importance placed upon such experience in the middle of the 19th Century.

It is not surprising, therefore, that as engineering education developed in the United States, the first educators were drawn from practice; nor that early curricula dealt with the art of engineering and consideration of existing engineering works and systems. As our fund of scientific knowledge expanded, its value in the solution of engineering problems became increasingly evident.
Coupled Geomechanical and Reservoir Modeling Investigating Poroelastic Effects of Cyclic Steam Stimulation in the Cold Lake Reservoir
Authors: Walters D. A. , Settari A. , Kry P. R.
Published: December 2007

The heating of bitumen reservoirs by cyclic steam stimulation (CSS) requires high pressures and temperatures that disturb the soil matrix. This disturbance results in a dilation of the soil matrix, creating regions of enhanced permeability and porosity, which impact both the injection and production cycles of steam stimulation and the porous zones not hydraulically connected to the reservoir. The volumetric strain changes reach far beyond the region of injection and include areas of both expansion and compression. The magnitude of the volumetric strains may result in significant displacements and strains being transferred to porous zones outside the reservoir. This can result in observable pressure changes in an otherwise hydraulically static system.

Pressure data at an observation well drilled to monitor aquifer pressures showed a significant response to the CSS process occurring in the reservoir approximately 300 m below the aquifer. Coupled geomechanical and reservoir modeling and an analytical calculation both show that this pressure behavior is attributed to the poroelastic response of the aquifer caused by the CSS process occurring in the reservoir. This paper describes the field data, the methodology of the coupled reservoir and geomechanical modeling, and the result of the analysis of the field data with the coupled model. The analysis shows clearly that the aquifer response is not caused by a hydraulic communication with the reservoir. It also shows the capabilities of coupled modeling, as this type of a problem could not be analyzed with conventional reservoir simulation tools.
Field-Scale Characterization of Permeability and Saturation Distribution Using Partitioning Tracer Tests: The Ranger Field, Texas
Authors: Illiassov Pavel A. , Datta-Gupta Akhil
Published: December 2007

This paper discusses the application of an efficient streamline-based inversion method to a large multiwell multitracer Partitioning Interwell Tracer Test (PITT) in the McClesky sandstone, the Ranger field, Texas, to characterize both permeability and oil saturation distribution. During a typical PITT, a conservative and a partitioning tracer are injected into the reservoir. The partitioning tracer gets partially absorbed into the oil phase, leading to a separation in the tracer responses that can be used to infer oil saturation distribution in the tracer-swept area. Our approach is extremely efficient because it relies on analytic computation of the sensitivity of the tracer response to reservoir parameters such as permeability and saturation using a single streamline simulation. We follow a two-step procedure whereby we first match the conservative tracer response to determine the permeability distribution, and then match the partitioning tracer response to obtain oil saturation distribution in the reservoir. The entire history matching took less than 6 hours on a PC as opposed to several months typically required for a manual history matching.

We compared our results to a manual history match obtained using a finite-difference simulator. Both the manual history matching and the streamline-based inversion identified similar large-scale trends in permeability and saturation distribution. However, well-specific matches were significantly improved over those obtained through the manual history matching. Our approach is much more efficient in terms of computation time and effort, and the results are less sensitive to personal bias compared to manual history matching. Finally, we discuss a procedure to assess the results in terms of resolution of the estimates of permeability and saturation distribution.
Auk Field Development: A Case History Illustrating the Need for a Flexible Plan
Authors: Ray Buchanan , Hoogteyling Laurens
Published: December 2007

The Auk field produces from thin, but highly permeable, Zechstein dolomites. The reserves of the field were defined poorly after the initial four wells were drilled, primarily because of the lack of seismic control. This paper contrasts the initial development plan with the historical sequence and shows how unexpected reservoir response was monitored and interpreted and how it influenced development drilling.

Introduction

The Auk field, discovered in 1971, is not typical of the North Sea. This small carbonate oil reservoir already has reached an advanced stage of development. All except one of the 10 slots on the drilling/production platform have been drilled - some deviated at angles up to 65°. The cumulative production is already more than one-half the estimated ultimate recovery.

The field is unusual in that the very thin Zechstein carbonate producing horizon could not be mapped directly by seismic data, so that both the structural attitude and areal spread of the accumulation initially were defined very poorly.

Potential difficulties during development of the Auk field were apparent at an early stage, and we realized that a flexible approach would be needed. A small integrated team of specialists was responsible for planning the development strategy. This team included a seismologist, geologist, reservoir engineer, production engineer, and an economist. Planning decisions thus have benefited from multidisciplinary analysis, and conclusions and recommendations were those of the whole team. This approach proved both necessary and effective.

The main aim of this study is to illustrate how the continuous flow of information necessitated radical revisions of our initial concepts of the Auk field and how development plans were modified continually. Because of space limitations, it is impossible to detail how the views of the various disciplines interacted when formulating each proposal. However, the overriding factors are pointed out, and the reasoning behind changes of policy are indicated.

Discovery and Appraisal

Shell/Esso's Field A in the U.K. North Sea (Auk) was discovered when Well 30/16-1, drilled in about 280 ft (85 m) of water, encountered oil-bearing, thin, vugular Zechstein dolomites unconformably overlain by Cretaceous chalk.1 The well tested 5,900 B/D (938 m3/d) of 37°API (0.84 g/cm3) oil with an extremely high productivity index. The underlying Rotliegend formation, which had formed the main objective of the well on the pronounced Auk horst structure, was found to be water-bearing.

Because the thin Zechstein formation could not be distinguished on seismic sections, the extent of the accumulation was in doubt. The high productivity of the Zechstein formation also could have been a local phenomenon because tight Zechstein was present in nearby exploration wells.
Analytical Modeling of Oil Recovery by Steam Injection: Part 2 – Asymptotic and Approximate Solutions
Authors: Yortsos Y. C. , Gavalas G. R.
Published: December 2007

This article studies the development of asymptotic and approximate solutions for the growth of the steam zone in steam injection processes in one-dimensional reservoirs at constant injection rates. These solutions generally are derived by using integral balances which include heat losses to the surroundings and the hot liquid zone. In this way, the effects of preheating caused by heat transport in the hot liquid zone ahead of the steam front are accounted for completely.

At the beginning of injection, the advance of the front is well described by the Marx-Langenheim (ML) model, provided that the injection rates are sufficiently high. At longer times, deviations occur and a criterion is developed in terms of a single heat transfer dimensionless parameter, R, that defines the time interval of applicability of the ML model. The asymptotic behavior at large times depends solely on a dimensionless parameter, F, defined as the ratio of the latent to the total heat injected. It is shown that the final dimensionless expression does not depend on R (i.e., on the injection rates) although the time taken to reach the asymptotic state is influenced significantly by R.

An approximate analytical solution that reduces to the respective asymptotic expressions at small and large times is obtained under conditions of high injection rates (R ≫ 1). The solution is shown to give a better approximation to the steam-zone growth rate for intermediate and large times than the approximate expressions developed by Marx and Langenheim,1 Mandl and Volek (MV),2 and Myhill and Stegemeier (MS).3 For a wider range of operating conditions, including low injection rates (i.e., for R between 1 and ∞), an approximate numerical solution based on a quasisteady state approximation is presented. The proposed solution requiring very modest computation is expected to give reliable results under a variety of operating conditions.
Oil/Water Separation in Liquid/Liquid Hydrocyclones (LLHC): Part 1—Experimental Investigation
Authors: Gomez Carlos , Caldentey Juan , Wang Shoubo , Gomez Luis , Mohan Ram , Shoham Ovadia
Published: December 2007

An extensive experimental program has been conducted using a 2-in. hydrocyclone. The inlet flow conditions are: total flow rates between 18 to 27 GPM, oil-cut up to 10%, median droplet size distributions from 30 to 180 μm, and inlet pressures between 60 and 90 psia. The acquired data include the flow rate, oil-cut, and droplet size distribution in the inlet and in the underflow; the reject flow rate and oil concentration in the overflow; and the separation efficiency. Additional data were taken from the literature, especially from the Colman and Thew1 study. This experimental investigation provided insight into the hydrodynamic flow behavior in the liquid/liquid hydrocyclone (LLHC), and helped develop and refine a mechanistic model for the LLHC, which is presented in Part 2 of this paper.
Assessment of Salt Loading on Well Casings
Authors: Willson S. M. , Fossum A. F. , Fredrich J. T.
Published: December 2007

Assuring the integrity of subsalt wells in the deepwater of the Gulf of Mexico throughout the field's life is a major drilling engineering challenge. The consequences of well failures may result in billions of dollars in remedial costs and lost production. On the other hand, the costs associated with overly conservative well design are significant, which motivates systematic analysis of casing loading for scenarios of interest.

Simplified hole-closure and casing-design guidelines for salt, many developed for the western U.S. Overthrust Belt, are not appropriate for the relatively pure, slow-moving halite found along the Gulf Coast. Instead, our work applies knowledge gained by Sandia Natl. Laboratories from technical research and development (R&D) investigations of the Waste Isolation Pilot Plant (WIPP) and the Strategic Petroleum Reserve (SPR) to determine the magnitude and timing of salt loading on well casings in the Gulf of Mexico.

If hole quality can be assured, the analyses presented show that it is not always necessary to cement the casing/borehole annulus through the salt because the subsequent uniform loading is insufficient to substantially deform the casing. This poses no threat to drilling operations or impingement on the inner casing string in the long term and results in considerable cost savings. However, if hole quality is poor, a cemented annulus is necessary, as the cement effectively transforms the potentially nonuniform loading situation into one of uniform loading.

Significant benefits can accrue from quantifying the magnitude and timing of salt loading. Difficult cementing jobs and liner tiebacks can be omitted and a more aggressive well design adopted. The simplified well design, and the elimination of potentially troublesome operations, leads to millions of dollars in cost savings in individual wells.
New Horizons for Gas in Europe
Authors: Symonds Edward
Published: December 2007

Since 1956, when extensive gas reserves were discovered in Africa and Libya, and the discovery of the Groningen field in The Netherlands in 1960, the picture for a strong gas industry in Europe has been growing more distinct. Advances in gas transportation and storage are contributing to the prospect for gas usage in Europe. Although the present usage is low, the possibilities for favorable costs in relation to competing energy sources and the potential demand show the market is there. In addition to domestic usage, industrial markets can be developed for the future. Political as well as economic forces are discussed in relation to developing the gas markets in Europe.

Introduction

For some years, natural gas was the neglected child of the petroleum business. The position in the United States, where it accounts for nearly one-third of the primary energy used, was regarded as exceptional if not unfortunate, and there was a tendency to overlook the few other areas where it has reached a high state of development. Today, the enormous and rapidly growing hunger for energy outside North America suggests that gas will take its place alongside oil, and of comparable importance, in other major markets. In this transition, the lead is likely to be taken by Europe. This remained a somewhat remote possibility so long as the gas had to be brought nearly 3,000 miles from the large Middle Eastern reservesfor which substantial markets have still to be developed. Following the first Saharan finds in 1956, discovery that North Africa possessed both those reserves, now estimated at 55 Tcf, and extensive others in Libya, promised to change this picture. In 1960, the accessibility of gas to European consumers was still further increased by the discovery in The Netherlands of what has since proved to be the second largest field in the world. The Groningen reserves, now estimated at almost 39 Tcf, put The Netherlands ahead of Canadaalready a major gas-producing country with an area more than 250 times as large.

Progress in Gas Transportation

The prospect for gas usage in Europe is being further improved by advances in transportation and storage. Experience in North America has amply demonstrated the capacity of pipelines to transmit gas to remote consuming markets at highly competitive prices. With a cost of transportation from Texas to the New York area approximately 25cts/Mcf, or from the Alberta fields to San Francisco of 20cts/ Mcf, the low energy/volume ratio (and therefore low flexibility) of natural gas in relation to oil has been largely overcome in this Continent. But transportation costs here were not directly comparable with those in Western Europe so long as Middle Eastern or North African gas reserves were the only ones in sight. It has been estimated that the cost of a normal water-crossing is about twice that for a comparable pipeline laid on land.

JPT

P. 499ˆ
Optimization of the Productivity Index and the Fracture Geometry of a Stimulated Well With Fracture Face and Choke Skins
Authors: Romero Diego J. , Valkó Peter P. , Economides Michael J.
Published: December 2007

For a given reservoir of known permeability and dimensions, the proppant mass injected to the pay determines a unique proppant number. Unique to each proppant number, there exists an optimum dimensionless fracture conductivity that exclusively determines the optimum fracture dimensions.1

Impairments affecting flow perpendicular to the fracture surface are accounted for as fracture-face-skin effect. On the other hand, flow impairment caused by a reduction of the fracture conductivity near the wellbore is called choked fracture skin. Both effects have a large influence on the productivity of a fractured well.

In this work, the performance of a fractured well is calculated with a direct boundary element method. This method provides the dimensionless productivity index, and the model allows for the presence of each of the two different skin effects.

The fracture face skin was found to have a significant detrimental effect on the dimensionless productivity index, even changing the character of its dependence on the dimensionless fracture conductivity. The effect of the choke skin also was found to be potentially detrimental but less complex to account for because it can be represented as an apparent reduction in the proppant number.
Fulfilling the Promise of Low-Dosage Hydrate Inhibitors: Journey From Academic Curiosity to Successful Field Implementation
Authors: Mehta A. P. , Hebert P. B. , Cadena E. R. , Weatherman J. P.
Published: December 2007

Low-dosage hydrate inhibitors (LDHIs) have been actively investigated for more than a decade in both academia and the petroleum industry. The promise of LDHIs has been to provide a viable alternative to thermodynamic inhibitors, such as methanol and glycol. Inevitably, the journey of LDHIs from modest beginnings in the minds and laboratories of researchers to a technically robust, operationally simple, and economically viable alternative to conventional inhibitors has been fraught with challenges. In this paper we discuss some of the drivers leading to the development of LDHIs for application in severe deepwater environments. The different classes of LDHIs are discussed briefly, with an emphasis on the applicability window of each inhibitor type. We also provide a detailed summary of the successful implementation of LDHIs in deep water and summarize key learnings obtained from field deployment. We conclude by demonstrating the role of LDHIs in altering industry perspectives on hydrate control and their impact on the system selection and design of new field developments.