bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Engineering Aspects of Formation Stress Testing
Authors: Shaw J. S. , Amick P. C. , Snow G. N. , Graham R. L.
Published: December 2007

This paper presents the equipment requirements and field procedures needed for safely and efficiently conducting in-situ formation stress tests (stress tests). It is set apart from other papers which primarily present data and describe analysis procedures. This work briefly discusses when stress tests are practical and what can be learned. The majority of the work describes detailed equipment requirements and field procedures for openhole and cased-hole tests. Different considerations are also mentioned when working with nitrogen and water. Encountered and potential problems are discussed alerting the operator to equipment and events requiring careful attention. An example is provided outlining actual testing time and related costs along with the information obtained.
Predicting Horizontal Well Production Performance Using Type Curves
Authors: Aminian K. , Ameri S.
Published: December 2007

Significant potential natural gas resources remain in low permeability marginal reservoirs of the Appalachian Basin. Horizontal well as an alternative to fractured vertical well, has a significant potential to enhance the recovery from the low permeability gas reservoirs. This paper addresses the potential contribution of horizontal wells to increasing the economic recovery from the low permeability gas reservoirs.

The selection of horizontal well over vertical well in low permeability gas reservoirs must be based on engineering and economic feasibility evaluations. The accurate prediction of production rates is one of the most important variables for feasibility evaluation of horizontal wells. It is, therefore, desirable to develop and evaluate simple but reliable methods for predicting the production performance of the horizontal wells. The production performance of horizontal wells completed in the low permeability gas reservoirs can be predicted by utilizing production type curves without the need for costly and time consuming computer simulations.

The application of the production type curves and the issues concerning the production performance of horizontal wells in the low permeability gas reservoirs are discussed. In addition, pre-stimulation production data from a horizontal well in West Virginia is compared with the predicted results from the type curves in order to evaluate the applicability of the type curves.
Evaluation of the Breaker Concentrations Required to Improve the Permeability of Proppant Packs Damaged by Hydraulic Fracturing Fluids
Authors: Brannon H. D. , Pulsinelli R. J.
Published: December 2007

The permeability of proppant-packs may be significantly damaged by the gelling agents commonly used in hydraulic fracturing fluids. Several recent fracture conductivity studies have sought to quantify the damage caused by these treatment fluids over a wide range of environmental conditions. Very little, however, has been disclosed in the way of viable methods of minimizing or cleaning up the proppant-pack damage.

Breakers, both oxidative and enzymatic, have been recognized for many years as useful for degrading the viscosity of polymeric treatment fluids. The prevailing assumption was that breaking the treating fluid to a non-viscous state was sufficient to provide for the proppant-pack clean-up upon flowback. Recent studies have illustrated that the permeability is significantly impaired by the polymer residue even though sufficient breaker concentrations have been added to effectively reduce the fluid viscosity.

In this study, the concentrations of a commonly used oxidative breaker which are required to significantly reduce the proppant-pack permeability damage caused by polymeric treating fluids were determined. The fluids which were evaluated were based upon natural guar, derivatized guar (HPG), and hydroxyethyl cellulose (HEC).

The long-term proppant-pack permeability testing was performed using a modified API-type fracture conductivity cell which permitted fluid loss through two, ten square-inch cores. The test temperature was 160°F, which is believed to be below the range at which effective thermal degradation occurs.

Test results indicate that proppant-pack damage can be significantly reduced by the addition of elevated breaker concentrations. An understanding of the effects of breaker concentration on proppant-pack damage can be very useful in the effective design of fracturing treatments.
The Effects of Skin Damage Upon the Productivity of a Well Containing a Horizontal Borehole
Authors: Peterson S. K. , Holditch S. A.
Published: December 2007

The application of horizontal drilling to enhance the production of oil and gas is a topic that has received much attention in the petroleum industry during the past few years. Numerous papers have been published concerning horizontal drilling technology,1-10 completion techniques involved with horizontal wells,11-20 well test design and analysis in horizontal boreholes, and reservoir performance prediction and analysis techniques.25-39 Even though publications are available on these topics, much of what is known within the industry has not been published due to proprietary concerns. Specifically, very little production data and field case histories have been included in the literature. Information concerning the production performance of wells completed with horizontal boreholes is extremely critical to one attempting to evaluate the usefulness of this technology.40

There are many well publicized applications for horizontal wells,41 such as; Improving recovery from naturally fractured reservoirs with widely spaced fracture systems;Producing gas from low permeability reservoirs near aquifers without barriers to hydraulic fracture height growth;Producing shallow, thin reservoirs with large areal extent in which one horizontal well can drain an area that would require multiple vertical wells to properly deplete;Producing reservoirs with thin oil columns and an overlying gas cap or underlying aquifer in which coning occurs at low flow rates from vertical wells; andImproving sweep efficiency in reservoirs where enhanced oil recovery projects are being implemented.

This paper discusses the application of horizontal wells for stimulating low permeability gas reservoirs where hydraulic fracture treatments are normally needed but, for whatever reason, cannot be successfully executed. In many low permeability gas reservoirs, long hydraulic fractures are needed to optimize production and profit from that reservoir.42 If weak barriers to vertical fracture height growth exist, then it may be physically impossible to create long fractures. In other situations, fractures may grow into aquifers or other intervals that prevent optimum performance.
Characterization of Formation Damage in Heavy Oil Formation During Steam Injection
Authors: Okoye C. U. , Onuba N. L. , Ghalambor A. , Hayatdavoudi A.
Published: December 2007

Enhanced oil recovery processes can lead to severe and permanent reductions in permeability due to interactions between injected fluids and reservoir rock. This is true particularly in high clay content and poorly consolidated reservoirs. Near wellbore permeability damage was suspected as a factor contributing to post injection production decline observed during high PH cyclic steam injection at Bayou Bleu field. This paper presents the laboratory studies undertaken to evaluate the influence of injection fluid composition, temperature, mineralogy and flow rate on permeability damage. The degree of damage during steam injection was observed to be dependent on PH, rock clay content, temperature and injection rate. Permeability reduction of up to 21% was observed in some cores at varying temperature and PH values for flow test and up to 70% for Rolling Oven test. Partial permeability restoration was obtained in all cases by reversing the direction of steam injection in the cores. Sandstone interaction with high PH steam leads to incongurent dissolution of clay minerals and subsequent precipitation of new aluminosilicates. Steam with caustic soda additive precipitated crystalline zeolite between temperatures of 100° and 300°F, mixture of zeolites and amorphous compound between 300° and 400°F and amorphous precipitate between 400° and 500°F. Mechanical fine migration and hydrothermal effects constitute the primary damage mechanisms when low PH steam is injected into Berea sandstone. The permeability damage due to fine migration was found to be rate sensitive while the damage caused by hydrothermal effect increased with increasing temperature. For high PH steam the primary damage mechanism is chemical dissolution and precipitation of aluminosilicates. The complex chemical activities were found to be temperature and alkali concentration dependent. While increasing temperature and alkali concentration generally increased the dissolution process the precipitation of certain aluminosilicates (zeolites) are inhibited at high temperatures and alkali concentration leading to improved permeability. SEM analysis revealed that the precipitates clogged pore spaces and plugged pore throats. High flow rate reduced the amount and rate of precipitation but at field scale flow rates the precipitation rate was high enough to cause rapid permeability reduction.
Evaluation of Acid System Design and Formation Damage Using Polarized Microscopy
Authors: Dunlap D. D. , Houchin L. R.
Published: December 2007

The evaluation of acid returns is an important tool for optimizing future acid treatments. The physical and chemical properties of the returned fluid are indicative of the rock and fluid interactions which occur during a formation treatment. Polarized microscopy is also an important part of this evaluation. The use of a microscope in return acid analysis permits the detection of specific damage mechanisms such as emulsions, organic deposits, silts, clays and iron.

This study details the use of polarized microscopy and other analytical techniques in thirty-two field applications in oil bearing sandstone formations located in the Gulf of Mexico, California and Alaska. Based on the results of these evaluations, modifications were made on future treatments to optimize stimulation results.
A Qualitative and Quantitative Evaluation of Fracture Treatment Variables Employing a Digital Computer Program
Authors: Harp L.J. , Crawford H.R. , Zachary R.A.
Published: December 2007

This paper describes an approach used in a large gas reservoir to develop a method for more accurately evaluating the effects of treatment variables. The study resulted in an empirical equation which will predict the productivity increase, for any set of treatment conditions, with reasonable accuracy. The value of such a workable tool is quickly realized. Emphasis and resources can be directed toward the important variables. Cost reduction and savings can be made in the area of variables having minimal or negative effects. With this tool, treatment planning, well selection, and economic considerations become relatively simple and confident decisions.

The success of this program indicates that this, or a similar method, can provide more effective and profitable stimulation treatments in other large fields.

Introduction

Since the advent of fracturing in 1949, the industry has witnessed refinement of the process resulting in the development of dozens of additives, processes, theories, and improved methods. Theoretically, all of these things contribute to the overall results of the treatment. Most assuredly, they contribute to the treatment cost. The questions that haunt many of us are—- "Do all of these things really contribute to the overall productivity increase? If so, to what degree does each contribute with respect to its cost?"

In the past we have been content to reach decisions on the basis of theoretical benefit, feel, and hope. Today, pressure for greater assurance of treatment segment effectiveness and economics insists upon a more accurate and dependable method of variable evaluation.
Prediction of Fracture Gradients Offshore Australia
Authors: Vuckovic V.
Published: December 2007

Previous work on developing an empirical correlation between in situ formation stress and depth for some sedimentary basins worldwide has demonstrated that such a correlation is viable for predicting fracture and leak off pressures. These parameters, together with pore pressures, are essential for proper well design from both an economic and a safety viewpoint.

Leak off pressure data have been gathered and analysed from wells drilled offshore Australia to establish empirical correlations which would be applicable for fracture gradient prediction in Australian offshore regions. The empirical relationship between in situ formation stress and depth derived from this study may be used with a high degree of confidence to predict leak off and fracture propagation pressures necessary for safe and economical well design in less than 600 ft (183 m) of water. These correlations can be extended to deep water regions by the application of a single correction.
Evaluation of Hydraulic Fracturing Applications in Central Australia
Authors: Lee B. O. , Salter G. B.
Published: December 2007

Some low permeability reservoirs in Central Australia require successful hydraulic fracture stimulation of production and injection wells to enable economic development. The techniques available to determine the created fracture properties include post-fracture pressure transient analysis and production performance history matching. The results of such evaluation will indicate the design changes required for optimum future treatment efficiency.

The methodology of detailed well test analysis for a number of fractured wells in an oil reservoir is described. Type curves and specialized plots for individual flow regimes are used in the analysis. Post-fracture pressure transient behaviour for these wells is generally bilinear flow dominated. The analysis results are validated by production history matching and indicate that future cumulative production for most wells in this reservoir could be further increased by improvements in created fracture conductivity.
Well Spacing For Primary Production And Pattern For Secondary Production As They Might Affect Ultimate Recovery
Authors: Orr Robert M.
Published: December 2007

Conclusions regarding primary spacing and secondary pattern as related to ultimate recovery were drawn from observation of the performance of numerous waterflood projects in the Sand Belt Trend of the Permian Basin in West Texas and Southern New Mexico.

Noting the trend toward wider and wider spacing in solution gas drive fields and the tendency toward not drilling any new wells for waterflood development, we made a study of nine comparable fields in this area, drilled on various spacings, in an effort to find some definite answers to the relationship of well spacing to ultimate recovery.

Some rather startling performances were observed that were contrary to most of the present thinking concerning the performance of solution gas reservoirs. For example, it was found that wells drilled on close spacing produced almost as much primary oil as did wells drilled on wider spacing. On the other hand, the secondary (waterflood) recovery was so much greater in the wide spaced areas that the combination of primary and secondary turned out to be the same regardless of the original spacing. It should be pointed out that we are dealing with reservoirs that have exceptional floodable characteristics. It is not contended that all solution gas reservoirs will respond in the same manner, except as to primary producing performance.

Introduction

For the past several years the tendency has been toward wider and wider spacing in developing new oil fields. At hearings conducted by state regulatory bodies, in the literature and in papers presented at conventions appear statements indicating that spacing makes no difference in the ultimate primary recovery in solution gas drive oil fields. Continuity of permeability, as evidenced by pressure interference tests, is being considered as synonymous with drainage of oil.

Not being convinced that this was true, or even being significantly close to being true, we decided to make a study of this problem with whatever information was available.
Toughness Requirements for Downhole Tubulars
Authors: Kermani M. B. , McKendrick R. D.
Published: December 2007

Premature and unexpected downhole failures are costly and introduce inefficiency in drilling and production operations. The integrity of tubulars used in these operations can be enhanced by reducing the risk of crack initiation through minimising the intensity of stresses ahead of existing defects, together with using materials of high fracture toughness properties.

Many material specifications now include minima for the V-notch Charpy absorption at one or more temperatures. However, Charpy values are inadequate in defining accurately the fracture toughness properties, determining the critical defect size and establishing.the conditions under which such a defect would become unstable.

Therefore, the crack tip opening displacement (CTOD) approach of general yielding fracture mechanics has been used to assess the toughness requirement of a range of downhole tubulars at ambient and various sub-zero temperatures. The materials studied included drillpipe and casing which fall within the category of API Specs 5D and 5CT and bottom hole assembly components covered by API 7A. This assessment was supported by carrying out fitness for purpose evaluations in accordance with British Standard PD 6493. Minimum safe values for the fracture toughness (CTOD values), relating to the body and threaded sections of tubulars with respect to the presence of possible defects, have been calculated.

In addition, the Charpy V-notch properties of the steels have been correlated with those of critical CTOD values. These relationships will enable materials and drilling engineers to specify adequate fracture toughness properties using relatively inexpensive and simple Charpy impact tests.

The results have clearly identified necessary toughness requirements for a range of typical tubular materials. It is recommended that a similar fracture mechanics approach, specifying the Charpy impact values, be adopted by API in future tubular specifications. This would ensure that a tubular is "fit for purpose" and thus minimise the occurrence of costly brittle failure of downhole tubulars.
Bit Whirl: A New Theory of PDC Bit Failure
Authors: Brett J. F. , Warren T. M. , Behr S. M.
Published: December 2007

This paper presents the results of a study investigating PDC bit vibrations. The study shows that the most harmful vibrations can be attributed to a phenomena called "bit whirl". During whirl the instantaneous center of rotation moves around the face of the bit, and the bit backwards whirls around the hole. Cutters on a whirling bit can move sideways, backwards, and much faster than those on a true rotating bit. The impact loads associated with this motion cause PDC cutters to chip, which, in turn, causes accelerated wear. Lab and field results showing the detrimental effects of whirl on PDC bit penetration rate and life are included.
Monte Carlo Simulation of Lithology from Seismic Data in a Channel-Sand Reservoir
Authors: Doyen P. M. , Guidish T. M. , de Buyl M. H.
Published: December 2007

In areas of rapid lithologic variations, the areal extent of sand and shale units usually cannot be inferred from sparse well data alone. Seismically derived interval velocity data can be used to help predict lithologic variations away from wells. However, in general, the overlap of the velocity ranges for sands and shales is such that seismic discrimination of lithology is ambiguous. We present a Monte Carlo technique for numerically simulating the spatial arrangement of sand/shale units. This technique accounts for the ambiguous nature of the seismic velocity information. Rather than calculating a unique sand/shale model, the Monte Carlo method provides a family of alternative lithologic images, all of which are consistent with the data. The range of models reflects the uncertainty of the lithologic classification and is used to assess risk in reservoir development. The sand/shale simulation technique is illustrated using a data set from an oil-producing channel-sand reservoir. Sand/shale cross-sectional simulations are generated along a seismic traverse that intersects three wells. The simulated models reproduce the log-derived lithologic sequences at the wells; they are conditioned by interval velocities inverted from the seismic amplitude data and are consistent with the spatial autocorrelation and cross-correlation structures of the seismic and well data. The seismically derived lithologic models of the reservoir are better spatially constrained than models solely conditioned by well data. However, in keeping with the inherent ambiguity of the seismic information, the exact location of the lateral truncation of the channel sand is not precisely defined in the Monte Carlo lithologic simulations.
A Structured Approach to Bridging the Research to Application Gap
Authors: Patel M. H.
Published: December 2007

This paper presents the historical background and structure of a joint industry funded international research programme which is specifically designed to be a bridging activity between fundamental work in research laboratories and the realities of practical application. The structure of the programme is described in detail including the procedures for organising funding, setting priorities and in managing the interface between research and application to ensure effective technology transfer. The concepts and philosophy underlying such a research programme are illustrated by drawing on five years experience of running one such programme entitled ‘Integration of Design Techniques for Offshore Structures’ at University College London.
International Implications of Technological Leadership: Part C—Worldwide Technical Organization
Authors: Grijalva V. E.
Published: December 2007

The international arena, specifically areas outside of North America, has increased in importance to those searching for oil and gas, for both economic and resource availability reasons. This creates a challenge to those accustomed to conducting business largely in the U.S. in best deploying their personnel and technological resources in an expanding international marketplace. Accordingly, this article addresses:

How can a technology-based company best structure itself to provide professional services and/or products throughout the world?

No stranger to the international marketplace, Schlumberger has had one mission from its inception--to provide the oil industry with value services to find and produce oil and gas efficiently and safely. From this broad philosophical foundation, the company has spent over sixty years molding an organization that will sustain its international focus on quality technology and service.

It is this organization that will be discussed herein, with the goal of identifying operational concepts and procedures that may help others to effectively disseminate and apply the latest petroleum technology worldwide.
A Comparison of Unstable Miscible and Immiscible Displacements
Authors: Peters E. J. , Hardham W. D.
Published: December 2007

Flow visualization experiments were conducted to compare the insitu displacement mechanisms of unstable miscible and immiscible displacements. A number of corefloods were imaged in time and space using x-ray computed tomography.

Results show that three displacement mechanisms are active in unstable miscible displacements whereas only one of these mechanisms is active in immiscible displacements. Therefore, unstable miscible displacements are more efficient than their immiscible counterparts because of a fundamental difference in their displacement mechanisms.
The Thin Flame Technique for In-Situ Combustion Simulation
Authors: Davies R. J.
Published: December 2007

This paper describes an approach taken to overcome the problems caused by grid block size effects in field scale in-situ combustion simulations. A new method called the thin flame technique is presented which approaches the problem by decoupling the flame from the conventional finite difference simulator and solving seperately for the flame speed and reaction rate. The thin flame technique uses the flame speed and reaction rate to advance a thin boundary representing the flame through the grid. This boundary acts as a moving heat source and displacing pump.

The solution of the decoupled flame is achieved using a steady state analysis that models the burning region using a reduced set of the conservation equations, and applies a moving grid to the region resulting in a two point boundary value problem. This is solved using a simple shooting method. The steady state analysis is derived for a system modelled by a single chemical reaction, and its solution by the shooting method is described. The analysis is compared with experimental results giving good agreement for the flame parameters.

The reaction rate and flame velocity determined by the steady state analysis are then used to apply the thin flame technique to the conventional simulator. This requires the redistribution of components within the burning grid block in order to correctly represent the saturations in the flow terms and provide boundary values for the steady state analysis. The application of the technique is described and results are presented of comparisons with the conventional simulator.
Miscible Flood from Inception: The Brassey Field Development, British Columbia, Canada
Authors: Whitten M. D. , Anderson J. H. , Tinker G. E.
Published: December 2007

The Brassey field, located in northeast British Columbia, Canada, is a dune sand reservoir, containing a volatile, undersaturated oil. The "Artex" sand is approximately 12 feet thick and is interpreted to be part of a large aeolian complex. Primary recovery is uneconomic, so a miscible flood will be operated from inception. Development of this oil-wet reservoir required the simultaneous integration of petroleum engineering and geoscience disciplines. A British Columbia Provincial Government 24 month royalty holiday program encouraged the pursuit of an aggressive development plan. This resulted in final development drilling being conducted during the miscible flood facility installation.

Development was started by implementing an extensive seismic acquisition and pulse testing/pressure transient program to determine reservoir boundaries and continuity. The ultimate well density, pattern design, and well location were altered prior to startup, based on this program. Fundamental reservoir engineering methods were applied in determining oil-in-place, performance predictions, and the necessary EOR process.
Future Trends in Drilling Costs: A Cost-Based Perspective
Authors: Woods T. J.
Published: December 2007

U.S. drilling costs have fallen substantially since the 1982 peak reported in the Joint Association Survey. In 1987 average U.S. well costs were 54 percent of their 1982 peak. The decline in drilling costs has essentially offset the decline in gas and oil prices between 1981 and 1987. Nevertheless, drilling activity has declined substantially. The combination of lower drilling activity and lower charges for drilling has affected the financial health of the U.S. drilling and service industry, even though the Industry is substantially more efficient today than it was in the early 1980s.

If drilling activity is to recover in the future, drilling charges will have to recover to support the expansion of the drilling and service industry. These charges, however, will only be able to recover to the extent that resource economics will allow. If resource economics constrain the recovery of drilling charges, such that the drilling industry can only expand modestly, then the outlook for U.S. oil and gas production could become less optimistic. Therefore, the economics of the optimistic. Therefore, the economics of the drilling and service industry is as important to future U.S. oil and gas production as the outlook for oil and gas prices.
Analyzing the Flowing Performance of Oil Wells: Denver Unit CO2 Flood
Authors: Greene W. R.
Published: December 2007

A mathematically precise method for determining the flowing life of oil wells is presented. Development of the necessary "outflow performance curves" and "flow charts" using multiphase vertical flow calculations is explained and illustrated graphically. An example study of 377 wells in the Denver Unit CO2 flood in the Wasson (San Andres) Field, Texas, is used to demonstrate this calculation procedure.
Requirements for Corrosion-Resistant Alloy (CRA) Production Tubing
Authors: Petersen C. W. , Bluem M. F.
Published: December 2007

The incentive to use corrosion-resistant alloy (CRA) production tubing has grown as bottomhole temperatures have steadily increased above 325°F, as corrosion control costs have grown, and as many operations have sprung up in remote sites with limited accessibility. This paper discusses procedures to ensure acceptable manufacture of such tubing and also presents some operational experiences with these alloys.
Behavior of Coal-Gas Reservoirs
Authors: Cervik Joseph
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the SPE 4th Annual Eastern Regional Meeting to be held in Pittsburgh, Pa., Nov. 2–3, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Gas occurs in coalbeds in an adsorbed and a free gas state. Adsorbed gas is stored in the micropore structure and its transport is governed by Fick's law. The free gas occurs in the fracture system and flows according to Darcy's law. These two modes of mass transport are interdependent. Production decline curves are of the constant percentage decline type and, thus, show no indications of flow characteristics peculiar to coal-gas reservoirs. The effectiveness of surface boreholes as a degasification scheme depends upon both good fracture permeability and a high fracture density. Conventional methods of reservoir engineering analysis are not applicable to coalbeds.

Introduction

Mining of deep coalbeds (1,500 to 2,000 ft.) and production of the associated gas is analogous to a gas well with an expanding well bore radius. Gas production of 10 to 15 MMscfd is not uncommon from deep mines. State and Federal codes require that each unit vol. of gas be diluted with approximately 100 vol. of air. Methane-air mixtures in the range 5 to 15 pct. methane are explosive.

Mining deeper coalbeds requires smaller mine openings and these mines tend to be more gassy. Thus, the use of ventilation (dilution) as a means of controlling methane concentrations at active face areas and in the returns is limited severely. Degasification of coalbeds prior to mining and methods of controlling the flow during mining are necessary. Before effective methods of control and degasification can be developed, the laws governing mass transport through coalbeds must be understood.

The purpose of this paper is to present the fundamental concepts governing the transport of gases through a coalbed, and to define one of the environmental problems related to rapid, economical, and safe mining of coal deposits.

MICROPORE STRUCTURE OF COAL

Coal is formed from plant substances which mere preserved in various states of degradation in a favorable environment, and later altered by chemical and physical processes. However, there is no universal agreement on what chemical and physical changes take place in the transformation of plant substances to coal.
A New Technique for Laboratory Measurement of Acid Fracture Conductivity
Authors: Malik M. A. , Hill A. D.
Published: December 2007

A new type of cell has been developed and tested which can be used in the laboratory to simulate acidizing of a vertical fracture with and without fluid loss. Also, the acid-etched fracture conductivity can be measured under various levels of load.

Five experiments have been performed with this cell using Indiana limestone or Glen Rose limestone for acidizing and conductivity measurement. In two of these experiments, fluid loss was allowed from the fracture walls during acidizing. The etching patterns observed differed markedly from those seen in a cell in which the flow was radial through a horizontal fracture. The measured fracture conductivities dropped sharply at closure stresses of 3000 to 4500 psi, apparently due to crushing of the etched fracture faces.
553-ft Gravel Pack Uses Clarified XC Polymer: Development and Application in Beluga River, Alaska
Authors: Engel H. R. , Powell J. W. , Sigurdson S. R.
Published: December 2007

ARCO Alaska, Inc. (AAI) began using a clarified xanthan gum (XC) biopolymer to viscosify gravel pack slurries in 1987. More effective polymer hydration and filtration techniques were developed during several field applications. Current methods not only simplify the preparation of this xanthan polymer at the well site, they improve fluid quality, producing filterability without the use of shearing devices and resulting in higher values for low shear rate viscosity in the filtered fluid.

In addition to the mixing technique being refined, the method of gravel placement also was modified. The changes in the placement procedure allowed the perforations to be packed with the gravel pack screens in the well, and led to a successful 553 ft zone gravel pack.

This paper will document how the current polymer preparation technique was developed and how the slurry placement procedure was applied. It also will stress the importance of onsite quality control to a successful gravel pack.
Proppant Flowback Control
Authors: Murphey J. R. , Dalrymple D. , Creel P. , Totty K. D. , Crump B. , Barr S.
Published: December 2007

A process for controlling proppant flowback after hydraulic fracturing operations has been developed and extensively field tested. In the procedure, fracture sand is coated with epoxy resin during the fracturing treatment. Unique wetting aids permit the rapid and complete epoxy resin coating of the sand while it is in the blender tub. Once placed in the fracture, the resin coated sand hardens to form a highly conductive, consolidated proppant bed which is resistant to flowback.

Fluid residence times and mixing parameters required to obtain rapid resin coating of sand were studied utilizing a laboratory scale blender to simulate typical fluid rates and mixing energy. Fracture flow capacity and compressive strength development with respect to application parameters were determined.

This paper presents results of field testing of this method and the development of metering and mixing equipment required to perform this process.
Vertical Permeability: Field Cases
Authors: Bourdarot G. , Daviau F.
Published: December 2007

This paper compares the vertical permeability of several field cases, as obtained using different techniques.

The vertical permeability of a reservoir is often of major importance: –where water or gas coning is likely to be a problem,–when pressure maintenance is carried out in multi-layer reservoirs,–in many reservoir simulation studies,–if horizontal wells are envisaged.

The following methods were used to determine the vertical permeability: –well test analysis: partial penetration, multilayer and horizontal well tests in both conventional and fractured reservoirs,–coning analysis,–RFT vertical gradient and build-up analysis.

A comparaison of the vertical permeability values obtained, using the various methods listed above, makes it possible to establish the interpretation consistency.

A comparison with core measurements makes it possible to evaluate reservoir homogeneity. When vertical permeability is measured from cores it is generally higher in comparison to measurements obtained using dynamic methods. This is because core measurements do not allow for middle scale fluid barriers.

Dynamic measurements of vertical permeability combined with statistical methods help determine the magnitude of fluid barriers causing permeability anisotropy in the reservoir.

In fractured reservoirs, vertical permeability is often low as a result of discontinuity of the fractures at the bedding planes. Well tests and coning analysis are the best methods for determining vertical permeability and evaluating fracture continuity in the reservoir.
Pressure Behavior of Compartmentalized Reservoirs
Authors: Stewart G. , Whaballa A. E.
Published: December 2007

The single phase material balance equations are derived for a complex reservoir comprised of an arbitrary configuration of rectangular compartments separated by partially communicating barriers. A system of linear ordinary differential and algebraic equations results which can be solved analytically by the methods of state space control theory. The concepts of boundary pressure time delay and desuperposition are introduced which allow the material balance equations to predict well bottom-hole pressures over all flow regimes (transient, late transient and semi-steady-state). Analytical methods allow the history-matching problem to be carried out very rapidly. Four prototype compartmentalised reservoirs are examined - an idealised cellular system comprising a series of identical cells, a two cell system where the supporting cell is very large, a stacked channel realisation and an aeolian dune sand realisation. The pressure response (drawdown and buildup) of these compartmentalised systems is analysed in detail showing how well testing - particularly extended drawdown and building testing - can be used in the identification of geological structure. A new method of pressure extrapolation based on exponential approach to an asymptotic value is shown to have a strong theoretical justification.
Interference Testing of Finite Conductivity Hydraulically Fractured Wells
Authors: Meehan D. N. , Horne R. N. , Ramey H. J.
Published: December 2007

This paper presents techniques for the design and analysis of interference tests when both the active and observation well are intercepted by hydraulic fractures. These techniques are based on new mathematical solutions. The solution is general for any values of dimensionless fracture conductivity including infinite conductivity. The solution is presented in Laplace space; fracture skin, wellbore storage, naturally fissured matrix behavior, etc. are readily included. Any rate or pressure schedule at the active well can be analyzed.

Compass orientation of the wells’ hydraulic fractures can be determined from such an interference test. Relative fracture lengths, conductivities, and azimuth significantly affect well performance. Reservoir heterogeneities may significantly alter interference response. The value of knowing hydraulic fracture azimuth can also be determined. Performance of a hydraulically fractured well near a large natural fracture or another hydraulically fractured well is also forecast. Values of fracture conductivity and fracture length for each fracture can not be determined uniquely from the interference response and must be determined seperately.
Determination of Front Locations in a Multilayer Composite Reservoir
Authors: Anbarci K. , Grader A. S. , Ertekin T.
Published: December 2007

A pressure transient interpretation method for multi-layer composite reservoirs with or without crossflow is presented. The proposed solution includes wellbore skins and storage effects and it is applicable to radial systems with either an infinite outer boundary, a constant pressure outer boundary or a closed outer boundary. Flood fronts in the layers may be located at different positions away from the well.

The detection of reservoir properties and the location of the fronts in the different layers plays an important role in the design and operation of secondary and tertiary recovery processes. The proposed new model addresses the need for an interpretation technique that provides the ability to monitor the location of flood fronts via pressure transient analysis.

The mathematical model is posed with the diffusivity equations for each layer and each fluid zone behind and ahead of the fronts. The boundary conditions at the interfaces can be with or without crossflow. The analytical solution is obtained using Laplace transformation. The new model is successfully tested with respect to four special cases presented in the literature. The sensitivity of the model to reservoir properties is also discussed.
New Pressure Functions for Well Test Analysis
Authors: Onur M. , Peres A. M. M. , Reynolds A. C.
Published: December 2007

In recent years, the pressure derivative has become a highly popular method for analyzing well test data. The main disadvantage of the pressure derivative is that one must construct derivative data by numerical differentiation of measured pressure data. The resulting pressure derivative data is often noisy and difficult to interpret. While various "smoothing techniques" have been used to reduce the noise in pressure data, there exists some concern that the smoothing procedures may alter the basic character of the data. In this work, we present new pressure functions based on the moving or cumulative average of pressure and its first and second derivatives. Using the average value of the pressure derivative is advantageous in that corresponding field data is much smoother than the standard pressure derivative data. It is shown that various combinations of these functions can be used to construct new type curves and to identify proper semilog straight lines.
Zuidwal: A Gas Field Development With Horizontal Wells
Authors: Celier G. C. M. R. , Jouault P. , de Montigny O. A. M. C.
Published: December 2007

Zuidwal is probably the first gas field development with horizontal wells. Originally, a development with fifteen conventional deviated wells was planned. Three horizontal wells have been drilled instead of six deviated conventional wells.

The field is a classical structural trap situated at a depth of 1900 m., with sandstone reservoirs of 100 m. thickness subdivided into several layers, two of which have excellent reservoir characteristics.

The main motivation to drill the wells horizontally is given by the conventional analysis of pressure drop in the reservoir:

– On a deviated well the non Darcian term of the pressure drop due to the gas velocity in the vicinity of the well accounts for an important part of the total pressure drop.

In a horizontal well this term is highly reduced and its productivity is much less affected by its rate.

As a result, horizontal wells will produce twice as much as the equivalent deviated well at only 20% additional cost.

The pattern of the wells consists of two horizontal sections of 100 to 200 m., drilled in the two good layers, joined together by a more and less deviated section. This profile must increase the drainage of these units and minimize eventual water coning.

Three horizontal wells have been drilled using the well-known technology of drilling and logging. The first one was completed in April 1988 and has been in production since August 1988. The two others, drilled in sequence, have been in production since March 1989.

The total lengths of subhorizontal sections of the three wells are 650 m., 540 m. and 610 m., respectively.

The first results of the wells show that the wells perform better than expected.

The main purpose of this paper is to present a review of the well behaviour (well testing, production logging, production history) in order to give useful background on horizontal wells in a gas field.
Estimation of Water and Oil Relative Permeabilities From Pressure Transient Analysis of Water Injection Well Data
Authors: Nanba T. , Horne R. N.
Published: December 2007

This paper presents an interpretation methodology to estimate water and oil relative permeabilities from pressure transient analysis of water injection well data.

This study has been carried out in three related parts. In the first part, mathematical equations for injection, fall off and variable-rate injection solutions are derived based on the multicomposite and stepwise multicomposite systems.

In the second part, the effect of water and oil relative permeabilities was investigated using the mathematical models. The investigation showed that the characteristics of the relative permeabilities are reflected distinctly in the transient part between the early and late time ranges.

In the last part, the inverse problem of estimation of water and oil relative permeabilities from pressure transient data was discussed using the proposed interpretation system, which consisted of the multicomposite model and an improved nonlinear regression algorithm. The study showed that the power-law relative permeability curves can be determined uniquely from pressure falloff data. Interpretation of field examples supported the practicality of the developed approach.
Applications of Emerging Well Testing Technology in South Texas Gas Reservoirs
Authors: Juranek T. A. , Pearcy M. S.
Published: December 2007

An emerging well testing technique, compressive IMPULSE Testing*, has been evaluated in tight, geopressured gas sands in South Texas. The technique relies on evaluating a reservoir's response to underbalanced perforating in a closed system. Bottomhole pressure is measured and analyzed to estimate reservoir pressure, permeability, and completion skin. Determining permeability, a critical stimulation design parameter, from conventional transient pressure analysis is often impossible or unreliable in these low productivity sands.

Results from several case histories were used to evaluate the reliability of compressive IMPULSE Testing. Other techniques such as conventional transient pressure analysis were used to validate these results. In the proper application, reservoir parameters can be obtained quickly and cost effectively using compressive IMPULSE Testing. Specific cases were chosen to demonstrate important operational considerations and limitations of the technique.