bluuebunny/crossref_metadata_2025 huggingface dataset:
Best Practices and Methods in Hydrocarbon Resource Estimation, Production and Emissions Forecasting, Uncertainty Evaluation, and Decision Making
Authors: Jonkman R.M. , Bos C.F.M. , Breunese J.N. , Morgan D.T.K. , Spencer J.A. , Søndenå E.
Published: December 2007

On behalf of a group of sponsors consisting of the Norwegian Petroleum Directorate (NPD) and most E&P companies active in Norway, a work group was established to author a report on the best practices and methods in hydrocarbon resource estimation, production and emissions forecasting, uncertainty evaluation, and decision making. The work group is part of Norway's forum for Forecasting and Uncertainty evaluatioN (FUN).

Following a detailed data acquisition and interviewing phase used to establish an inventory of the current practice of all sponsors involved, the work group postulated a relationship between a company's practices and its economic performance. A key distinguishing factor between companies is the degree to which probabilistic methods are adopted in integrated multidisciplinary processes aimed at supporting the decision-making process throughout the asset life cycle and portfolio of assets.

Companies have been ranked in terms of this degree of integration, and best practices are recommended. In many companies, a gap seems to exist between available and applied technology. Data and (aggregated) information exchange between governments and companies is also discussed. A best practice based on their respective decision-making processes is recommended.
Evolutionary Algorithms Applied to History Matching of Complex Reservoirs
Authors: Schulze-Riegert R.W. , Axmann J.K. , Haase O. , Rian D.T. , You Y.-L.
Published: December 2007

Conventional direct optimization methods and evolutionary algorithms are applied to the problem of history matching in reservoir engineering. The advantage of parallel computing for the optimization of complex reservoir models is investigated. Methods to improve the convergence of evolutionary algorithms by introducing prior information are applied.

The potential of using optimization methods for the problem of reservoir modeling in various modeling phases is discussed. The methodology is illustrated on realistic simulation cases. In conclusion, results suggest that evolution strategies can be applied successfully to generate possible solutions in the early modeling phase.
Formation Damage Abatement: A Quarter-Century Perspective
Authors: Ghalambor Ali , Economides M. J.
Published: December 2007

Petroleum well production impairment has long been associated with formation damage. Concepts such as the skin effect and its various manifestations have been introduced to account for the effects of damage. The origins of damage and the types of damage also have been the subjects of intense scrutiny. Abatement has included preventive measures such as the use of nondamaging fluids, presumably more benign processes, and improved drilling and well construction procedures and techniques. Once in place, the removal of damage has spawned an entire industry, that of matrix stimulation. This involves the use of appropriate remediation fluids, complete with the understanding of the often contrasting interaction among these fluids, the fluids and the damage, and, very importantly, the side effects that can damage the well more than its prestimulation state. Again, appropriate hardware was necessary. Owing to the fact that damage removal is often either incomplete or unsuccessful, methods of bypassing the damage, such as high-permeability fracturing, have been developed. Finally, brute force approaches are common, including the drilling of more vertical and/or horizontal wells regardless of the damage in order to get enough production. This paper is a critical review of both the evolution of the technologies and the thought processes that have permeated the industry over the past quarter century. Particular emphasis is given to the resolution of controversial subjects and their impact on the field. These include issues such as matrix stimulation vs. fracturing, sand production control vs. sand deconsolidation management, underbalance vs. extreme overbalance, and perforating and drilling fluids and practices.
Bottom-Hole Pressure Reduction Due to Gas Cut Mud
Authors: White Robert J.
Published: December 2007

Strong's equation for calculating bottom-hole pressure reduction due to gas cutting of drilling mud is corrected, resulting in a simpler equation which is easier to use. Use of the equation is illustrated by examples. It is shown that reduction of weight of a 10 lb/gal mud by 50 per cent at the surface due to gas cutting produces only a 3 per cent decrease in hydrostatic head at the bottom of a 5,000-ft well. It is also shown that at the surface 5 volumes of air per volume of mud are required to reduce the apparent mud weight from 8.5 to 6.5 lb/gal in a 3,000-ft well. Illustrative graphs are included to show the effect of various degrees of gas cutting on apparent mud weight at depths of 2,000, 5,000 and 10,000 ft and to show variation of apparent mud weight, with depth for a 100 lb/cu ft (13.37 lb/gal) mud gas cut to 90 lb/cu ft (12.03 lb/gal) at the surface.

Introduction

In 1938, Strong published the following equation for calculating reduction in bottom-hole pressure due to gas cutting of drilling mud.

This equation was recently found to contain an error due to an incorrect expression for variation of volume fraction of gas with pressure. Values calculated by the original equation are close to the correct values for small percentages of gas for which it was derived but become increasingly erroneous as the gas content increases and are completely unusable at the very high gas contents employed in aerated mud.
Characterizing the Greater Burgan Field: Use of Geochemistry and Oil Fingerprinting
Authors: Kaufman R. L. , Dashti H. , Kabir C. S. , Pederson J. M. , Moon M. S. , Quttainah R. , Al-Wael H.
Published: December 2007

This study reports reservoir geochemistry findings on the Greater Burgan field by a multidisciplinary, multiorganizational team. The major objectives were to determine if unique oil fingerprints could be identified for the major producing reservoirs and if oil fingerprinting could be used to identify wells with mixed production because of wellbore mechanical problems. Three potential reservoir geochemistry applications in the Burgan field are: (1) evaluation of vertical and lateral hydrocarbon continuity, (2) identification of production problems caused by leaky tubing strings or leaks behind casing, and (3) allocation of production to individual zones in commingled wells. Results from this study show that while oils from the major reservoir units are different from each other, the differences are small. Furthermore, a number of wells were identified in which mixed oils were produced because of previous mechanical problems. Both transient pressure testing and distributed pressure measurements provided corroborative evidence of some of these findings. Other data show that Third Burgan oils are different in the Burgan and Magwa sectors, suggesting a lack of communication across the central graben fault complex. This finding supports the geologic model for the ongoing reservoir simulation studies. Success of the geochemistry project has spawned enlargement of the study in both size and scope.
Application of a New Multicomponent Gas Adsorption Model to Coal Gas Adsorption Systems
Authors: Clarkson C. R.
Published: December 2007

A new multicomponent adsorption model is proposed for application to coal gas adsorption systems. The model is derived by combining the vacancy solution and Dubinin-Polanyi theories. Applications of the new adsorption model include the modeling of multicomponent adsorption processes associated with primary and enhanced coalbed methane recovery (ECBM).

In the new model, the adsorbed phase in the single-component (pure) adsorption system is treated as a binary mixture of a singlecomponent gas with a hypothetical "vacancy" species, which also occupies adsorption space. The adsorption system is modeled as equilibrium between the gaseous phase and the adsorbed-phase vacancy solution. The Dubinin-Astakhov (D-A) equation is used to generate activity coefficients, as a function of the degree of porefilling, for the pure component gas in the binary (adsorbate+vacancy) adsorbed-phase mixture. The Wilson equation is chosen to fit pure component (D-A-derived) activity coefficient curves by optimizing the binary interaction coefficients. These binary interaction coefficients are then used to predict multicomponent adsorption equilibrium, although only the case of binary adsorption is modeled here.

The adsorbed phase mixture for binary gas adsorption is treated as a ternary mixture of the two pure component adsorbates and the hypothetical vacancy species. Binary gas adsorption equilibrium is described by equilibrium between the gaseous components and the components in the adsorbed phase solution. Adsorbed-phase activity coefficients are calculated from the Wilson equation, with the binary interaction coefficients obtained from pure component adsorption data. Thus, only pure component adsorption data are required to make binary and multicomponent adsorption predictions with the new model.

Two binary (CH4+CO2) gas adsorption experimental data sets with coal as the adsorbent and one binary (CH4+C2H6) gas adsorption data set with activated carbon as the adsorbent are used to test the predictions of the new model. In most cases the new model is able to predict binary gas adsorption accurately. The poor fit of the Wilson equation to the D-A-derived activity coefficients for some pure component data suggests that some improvement in model predictions could be made with the choice of a different activity coefficient equation.

A unique feature of the current model is the ability to predict multicomponent gas adsorption at different temperatures from the pure component adsorption data collected at a single temperature. The temperature independence of pure component "characteristic" curves, as demonstrated in Dubinin-Polanyi theory, allows pure component adsorption to be predicted for a range of temperatures. These pure component data can then be used in modeling binary or multicomponent adsorption data at various temperatures. This is demonstrated for one experimental binary gas adsorption data set.
Well Service: Impact of Wellsite Monitoring on Economics, Standards, Performance, and Culture
Authors: Newman Fred M. , Dillingham Don , Ivanhoe Karl
Published: December 2007

This study produced a quantifiable database that provided analysis and interpretation of field activities over more than 20,000 rig-hours during a 14-month period. The data were obtained by sealed, independent, electronic measurement from selected well-service providers performing assorted jobs under a variety of conditions. This study was initiated because of a lack of known published or accredited standards or guidelines for assessing well-service performance. The primary focus was on overall job quality, rod and tubing makeup, time use, crew efficiency, and safety. Information was acquired with an unattended system, temporarily stored on the rig recording unit, and retrieved by wireless remote to a host PC at a central office. Archived data were analyzed graphically and tabularly and were reported to well-service and oil companies to develop and maintain well histories, publish crew-efficiency reports, identify optimum procedures, improve safety, and publish time studies. Current industry quality-assurance practice consists mainly of the occasional overview of well-service crews by a field engineer or foreman, relying on visual perception and experience in judging service quality and procedures. The results are extraordinary repeat failure rates and unresolved service problems. The new electronic-monitoring technology documents and resolves deficient intrinsic field cultural practices. Our data and analysis conclusively show that repeat failure rates and downtime are reduced. Service-crew awareness concerning work processes and efficiency is raised to a higher level. Productivity increases, artificial-lift costs decline, and fair accountability is maintained with permanent records. Oil companies use the new technology to establish and monitor their alliances; service companies use the results to train crews in proper techniques. Credible reporting now enables and mandates performance over personality when making long-term economic decisions. This technology will push the evolution of the well-service industry with the establishment of quality and performance standards. Quality standards, rather than perceptions, will be the basis for decisions.
Optimization of Well Placement in a Gulf of Mexico Waterflooding Project
Authors: Guyaguler Baris , Horne Roland N. , Rogers Leah , Rosenzweig Jacob J.
Published: December 2007

In this study, a hybrid optimization technique based on the genetic algorithm (GA), polytope algorithm, kriging algorithm, and neural networks is proposed to optimize a waterflooding project. Hybridization of the GA with these helper methods introduces hill climbing into the stochastic search and makes use of proxies created on the fly. It was observed that the number of simulations required was reduced significantly, as compared to conventional approaches. This reduction in the number of simulations reduced the computation time, enabling the use of full-scale simulation for optimization even for this full-scale field problem. It was also seen that the optimization technique was able to prevent convergence to local maxima owing to its stochastic nature.
Development of a One-Piece Liner Hanger/Liner Top Packer/Production Packer System for Monobore Wells in Alaska's Kuparuk River Field
Authors: Trantham J. A. , Anderson L. F.
Published: December 2007

To meet the need to reduce monobore tubingless completion costs, a combination device to hang a liner, seal the liner top, and perform completion-packer functions with a compact single unit has been developed. This combination system improved the economic feasibility of the Kuparuk River field monobore project in Alaska. This paper describes the system, discusses the benefit for a singletrip completion, presents test results, and addresses the running procedures for the single-trip multipurpose packer.
A Shear Dilation Stimulation Model for Production Enhancement From Naturally Fractured Reservoirs
Authors: Hossain M. M. , Rahman M. K. , Rahman S. S.
Published: December 2007

This paper presents a model for an alternative stimulation technology for naturally fractured tight gas or hot dry rock (HDR) reservoirs in which conventional hydraulic fracturing is relatively inefficient. The model stochastically simulates field-representative natural fractures by processing field data from cores, logs, and other sources. Deformations of these fractures are formulated as functions of fluid pressure inside fractures and in-situ stresses. The permeability enhancement and reservoir growth pattern are then formulated as functions of fracture deformations. While verified, the capability of the model to simulate field representative natural fractures is found to be satisfactory. The model is also applied to central Australian reservoirs to investigate permeability enhancement behavior with respect to various fracture attributes. The production performance of the proposed stimulation technology is assessed, and its potential for applications to tight gas reservoirs is also found to be very high.
Planning and Progress on Drilling a Record-Depth Well in the Rocky Mountains
Authors: Arnold Don R.
Published: December 2007

Introduction

Rainbow Resources Inc., as operator for the Pacific Creek Deep Unit, has drilled a record-depth well in the Rocky Mountains. The Pacific Creek structure, which was defined by seismic techniques, is about 200 miles (322 km) southwest of Casper, WY, and 60 miles (97 km) north of Rock Springs, WY.The well was spudded March 14, 1978, and breached a total depth of 25,764 ft (7853 m) on May 9, 1979. This surpassed the previous depth record of 23,081 ft (7035 m) held by American Quasar Petroleum Co. in their Sellers Draw Unit 2, Well 1, in Petroleum Co. in their Sellers Draw Unit 2, Well 1, in Park County, WY. This paper discusses the planning Park County, WY. This paper discusses the planning for this record-depth well including the casing design, mud program, cementing of the deep strings, and drilling progress and techniques used to total depth.

Geology and Structure

Fig. 1 is a generalized columnar section of the Green River basin. Superior Oil Co. originally drilled this structure to 20,521 ft (6255 m) in 1949 and held the world's depth record until 1952. Terra Resources Inc. drilled a 13,500-ft (41 15-m) test on the structure in 1974. The Superior well bottomed in the top of the Frontier formation, and Terra bottomed in the Rock Springs formation. This left all the possible productive formations from the Frontier to the productive formations from the Frontier to the Madison untested on the Pacific Creek structure. Fig. 2 shows the structure contoured on top of the Nugget formation. As shown, the structure encompasses two large anticlinal closures. The northern structure has not yet been tested. The drilling of Pacific Creek Deep Unit Federal 1-34 has confirmed Pacific Creek Deep Unit Federal 1-34 has confirmed that the Superior and Terra wells were not drilled on the top of the southern structure.

Drilling History

Drilling Rig

Parker Drilling Co.'s Rig 166 was used to drill Parker Drilling Co.'s Rig 166 was used to drill Federal 1-34. It is a diesel-electric rig and has an OIME Inc. Hercules E-3000 drawworks driven by two General Electric Co. 752 [1,000-hp (746-kW)] electric motors. The Lee C. Moore Corp. derrick is 142 X 30 ft (43 X 9 m) with 1.3 million lbm (589 670 kg) static hook load and 800,000 Ibm (362 874 kg) setback capacity. Prime movers consist of three Waukesha 5792's rated at 1,000 hp (746 kW), each of which drive generators that are fed through an SCR system.Mud pumps are two Continental-Emsco Co. FA-1600's. Two 6 X 8 in. (15.24 >< 20.32 cm) and two 5 x 6 in. (12.7 X 15.24 cm) centrifugal pumps are used for mud mixing. The rig is equipped with four 400-bbl (63.59-m3) mud pits and a 100-bbl (15.90-m3) trip tank.Drillpipe is 5-in. (12.7-cm) OD, 19.5-lbm (885-kg) Grades E and 5-135. Drill collars arc 9 1/2-in.

JPT
Discrimination of Natural Fractures From Drilling-Induced Wellbore Failures in Wellbore Image Data—Implications for Reservoir Permeability
Authors: Barton Colleen A. , Zoback Mark D.
Published: December 2007

Natural fractures and drilling-induced wellbore failures provide critical constraints on the state of in-situ stress and the direct applicability to problems of reservoir production, hydrocarbon migration, and wellbore stability. Acoustic, electrical, and optical wellbore images provide the means to detect and characterize natural fracture systems and to distinguish them from induced wellbore failures. We present new techniques and criteria to measure and characterize attributes of natural and induced fractures in borehole image data. These techniques are applied to the characterization of fracture permeability in two case studies.
Predicted Corrosion and Scale-Formation Properties of Geopressured Geothermal Waters From the Northern Gulf of Mexico Basin
Authors: Kharaka Yousif , Lico Michael S. , Carothers William W.
Published: December 2007

Introduction

Geopressured geothermal waters arc present at depths greater than about 2500 m in Cenozoic and Mesozoic sedimentary rocks beneath an area of about 350 000 km2 in coastal Texas and Louisiana. The hydraulic pressure gradients in the geopressured zones are higher than hydrostatic [10.5 kPa/m (0.465 psi/ft)], and with increasing depth approach the psi/ft)], and with increasing depth approach the lithostatic pressure gradient of 22.6 kPa/m (1.0 psi/ft). The temperature gradients in the psi/ft). The temperature gradients in the geopressured zones also are higher than the gradients in the overlying normally pressured zone. The temperature gradient in geopressured zones in south Texas is 67 deg. C/km (3.7 deg. F/100 ft); the gradients decrease northward along coastal Texas and Louisiana (Fig. 1). There currently is an intensive research and development effort by public agencies and private companies to determine the feasibility of using these geopressured waters as sources of energy. Three forms of energy may be extracted from these waters:(1)thermal energy,(2)mechanical (hydraulic) energy, because these waters will be under high pressure at ground level, and(3)energy obtained pressure at ground level, and(3)energy obtained from dissolved gases, mainly methane, which may exceed the thermal energy if the waters are saturated with natural gas under subsurface conditions.

This paper describes the chemical and physical parameters of selected geopressured geothermal parameters of selected geopressured geothermal waters that are important in determining their corrosion and scale-formation properties. The equations used here for predicting corrosion and scale formation apply to geopressured waters associated with oil and gas as well as geopressured waters from geothermal reservoirs. We have carried out detailed chemical analyses of 120 formation-water samples from geopressured and normally pressured production zones that range in depth from about 1000 to 5600 m. The 25 oil and gas fields sampled are in the McAllen-Pharr, Corpus Christi, and Houston-Galveston areas of Texas and in the Lafayette, LA, area. Oil and gas production is from sandstone reservoir rocks, which are mainly in the Frio Clay of Oligocene (?) age in Texas and of Miocene age in Louisiana.

Chemical Composition

Chemical analyses of eight formation-water samples selected as typical of the geopressured zone in their respective areas appear in Table 1, which also gives the locations of the sampled wells, subsurface temperatures, pressures, and other pertinent data. More complete chemical analyses, as well as the field and laboratory procedures used for collection, preservation, and analysis, are given in Kharaka et preservation, and analysis, are given in Kharaka et al.
Modeling Flow in Geometrically Complex Reservoirs Using Hexahedral Multiblock Grids
Authors: Jenny Patrick , Wolfsteiner Christian , Lee Seong H. , Durlofsky Louis J.
Published: December 2007

A hexahedral multiblock grid (MBG) formulation for the modeling of two-phase reservoir flows is developed and applied. Multiblock approaches are well suited to the modeling of geometrically complex features while avoiding many of the complications of fully unstructured techniques. Important implementation issues are discussed, including the accurate treatment of grid nonorthogonality and full tensor permeability (through use of a 27-point finite difference stencil), the treatment of exceptional cases arising when five blocks intersect, and a new well model that allows for the accurate resolution of near-well effects. Solution efficiency issues, including the use of tensor splitting and the linear solution technique, are also discussed. The actual grid generation step is accomplished using a commercial package. Results for a variety of cases involving flow through geologically complex systems and reservoirs with horizontal and deviated wells are presented. Comparison with analytical results demonstrates the high level of accuracy of the 27-point formulation and the new well model. The method is also applied to a realistic example involving flow through a heterogeneous faulted system. This example illustrates the types of geometrically complex systems that can be modeled using the hexahedral multiblock approach.
Acid Penetration in Natural Fracture Networks
Authors: Dong C. , Zhu D. , Hill A. D.
Published: December 2007

In this paper we present a methodology for predicting the propagation of acid along natural fracture networks and the resulting etching of the fracture walls. The natural fracture network is modeled as a system of intersecting fractures that form a main pathway for acid transport and dissolution. The tails of the intersected fractures increase the leakoff from the main pathway and are accounted for in the model. The fracture-network-acidizing model is supported by comparisons with laboratory experiments and smaller-scale simulations that determined the nature of acid channeling at fracture intersections. Model results illustrate the effects variations in fracture properties have on acid propagation. The model predicts deeper acid penetration under matrix conditions than would be possible with matrix flow only.
The Application of Rotary Closed-Loop Drilling Technology To Meet the Challenges of Complex Wellbore Trajectories in the Janice Field
Authors: Edmondson John , Abbott Chris , Dalton Clive , Johnstone John
Published: December 2007

A combination of rotary closed-loop steerable (RCLS) and conventional drilling technology was used to drill 3D complex development wells in the Janice field in the North Sea. Direct comparison of RCLS and conventional tools showed that RCLS gave smoother holes, higher rate of penetration (ROP), and lower cost per foot. The experience gained provides insights into where it is appropriate to use this new technology and demonstrates the applications for which RCLS technology can provide significant technical and economic advantages.
Foam for Gas Mobility Control in the Snorre Field: The FAWAG Project
Authors: Blaker Tore , Aarra Morten G. , Skauge Arne , Rasmussen Lars , Celius Harald K. , Martinsen Helge Andre , Vassenden Frode
Published: December 2007

The Foam Assisted Water Alternating Gas (FAWAG) project has been a full-scale field demonstration of foam for gas mobility control. It was carried out in the Snorre field on the Norwegian Continental Shelf from 1997 to 2000, with support from the European Commission's Thermie Program.

A production well treatment to reduce the producing gas/oil ratio (GOR) was performed in 1996. The FAWAG was initiated in the Central Fault Block (CFB) of the Snorre field in August 1998. A commercial surfactant system, AOS (α-olefin-sulphonate), with a carbon chain length mix of C14/C16, was chosen as the foaming agent. Approximately 2000 tons of commercial grade AOS surfactant have been injected.

Foam for mobility control in the CFB operation had to be aborted because of operative problems in the target injector P-25A. The main operational conclusion from the CFB operations was that surfactant alternating gas (SAG) injection is preferable to coinjection. Operationally, SAG injection is almost identical to water alternating gas injection (WAG), which is a well-known production method.

The concluding demonstration was performed on the Western Fault Block (WFB) in well pair P32-P39. The target injector and producer wells are approximately 1500 m apart. A total of 380 tons of commercial grade surfactant was used. The surfactant was divided into two slugs, each followed by gas injection that lasted until original gas injectivity was restored.

The production from WFB has shown that large volumes of gas have been stored, either temporarily or permanently, in the reservoir. It has been estimated that the FAWAG treatment has contributed approximately 250 000 Sm3 of oil. The cost of the treatment in WFB was approximately U.S. $1 million.
Applications of Streamline Simulations to Reservoir Studies
Authors: Samier P. , Quettier L. , Thiele M.
Published: December 2007

Computer models of oil reservoirs have become increasingly complex in order to represent geological reality and its impact on fluid flow. Memory and CPU time limitations by finite-difference (FD)/ finite-volume (FV) simulators force a coarser resolution of reservoir models through upscaling.

Upscaling can lead to significant difficulties in reservoir studies: (1) while the fine-scale geological model is built from petrophysical, log, and seismic data, its dynamic behavior is never checked. As a result, a coarse-scale reservoir study can be linked to a fine-scale geological model, but the two might be inconsistent in their dynamic behavior. (2) Conversely, the upscaled model cannot be properly tested because the flow and production behavior at the fine-scale level are not available. There is no reference solution for guiding important decisions for building a consistent upscaled model. (3) A large number of sector models are required in designing optimal well patterns.

Streamline simulation is now an attractive alternative to overcome some of these drawbacks because it offers substantial computational efficiency while minimizing numerical diffusion and grid-orientation effects. It allows the integration of fine-scale geological models into the reservoir engineering workflow.

In this paper, we demonstrate the usefulness and efficiency of a streamline simulator in the reservoir engineering workflow. We evaluate its speed, memory requirements, and scalability using tracer and black-oil-test data sets on an SGI Origin 2000™* (250 MHz MIPS). Our data are based on real fields and range from 200,000 to 7 million cells, with cells as small as 30×30×0.5 m. Streamlines allowed us to check the validity of a large geological model and to optimize well patterns with more than 30 producers and injectors. We demonstrate how streamline-based simulation has matured from a research tool to an industrial application providing real benefits to engineers as a complementary tool to existing conventional simulation technology based on FVs.
Higher-pH Acid Stimulation Systems
Authors: Abrams Albert , Scheuerman Ronald F. , Templeton Charles C. , Richardson E.A.
Published: December 2007

Two types of high-pH (4 to 6), mild-acting acidizing systems have been developed for in-depth rock matrix stimulation of both sandstone and carbonate reservoirs:self-generating (SG),** which utilizes the hydrolysis of an ester (or other acid producers) to generate low concentrations of H+, andbuffer-regulated (BR), which utilizes an organic acid buffered with its ammonium salt.

For sandstone stimulations, the HF acid generation is provided by the addition of ammonium fluoride. In-depth stimulation can be achieved with these systems from ambient temperature to about 280 degrees F [138 degrees C]. Near-wellbore damage removal can be obtained by using BR systems to at least 380 degrees F [193 degrees C]. Maximum application temperature is being determined now. Three SG systems have been developed for different operating temperature ranges: methyl formate (MF), for 130 to 180 degrees F [54 to 82 degrees C]; the ammonium salt of monochloroacetic acid (CA), for 180 to 215 degrees F [82 to 102 degrees C]; and methyl acetate (MA), for 190 to 280 degrees F [88 to 130 degrees C]. Similarly, BR systems have been developed for different pH ranges: formic acid (F) for pH 3.5 to 4.0, and acetic acid (A) and citric acid (C) for pH 4.5 to 5.0. Because of their moderate pH levels and low corrosiveness, BR systems also have potential application at temperatures where excessive corrosion precludes the use of conventional acids. Laboratory corrosion studies on BR systems show that corrosion rates, without inhibitors, are within acceptable limits to about 380 degrees F [193 degrees C]. Corrosion inhibitors should allow applicability to higher temperatures. This paper reviews the theory and experiments used in the development of these SG and BR systems. Field test results with these systems are presented in Refs. 1 through 4.

Introduction

Well stimulation acids have been designed traditionally on the basis of dissolving capacity, Therefore, concentrated acids such as 15% and 28% HCl and 12% HCl/3% HF have been used widely. These acid systems have pH values less than zero and are classified as strong acids. Both field experience and laboratory flow test results suggest that the amount of material causing impairment is probably small. However, because of its location in the flow channels in the rock, it can result in significant impairment. Further, the industry has been concerned for a long time with damage that may result from the release of fines and with the rapid reaction and depletion characteristics of low-ph acid stimulations. To meet the need for milder, slower-acting acids, we undertook a laboratory study that led to the development of the SG and BR systems described. Our field experiences with sandstone acidization have shown that mild acids and modified field procedures result in acid stimulation jobs with increased, stabilized oil production.

JPT

P. 2175^
Effect of Heat of Reaction on Temperature Distribution and Acid Penetration in a Fracture
Authors: Lee M. H. , Roberts L. D.
Published: December 2007

In a fracture acidizing treatment the acid reacts with the fracture faces. This acid/rock reaction generates heat that causes the acid temperature itself to increase. To predict accurately the temperature profile and acid spending rate of acid traveling down a hydraulically created fracture, this heat must be considered.

Since the heat generated by reaction depends on the reaction rate, the thermal energy equation must be coupled with the acid spending equation. A model has been developed that, for the first time, examines the effect of the heat of reaction on fluid temperature and acid penetration in a fracture. Some sample calculations have also been made to illustrate the effects of the most important parameters on acid penetration in a fracture.
Investigation of Changes in the Structure of Clays During Hydrothermal Study of Drilling Fluids
Authors: Carney Leroy L. , Guven Necip
Published: December 2007

The need for a drilling fluid that will exhibit its basic requirements at temperature levels high enough to be used for geothermal drilling has prompted studies of various systems.1 The temperature range of some of these studies has been between ambient temperature and 700°F (370°C). A system was developed that exhibited the desirable properties of a good drilling fluid system at elevated temperatures and pressures. A fluid that exhibited these desirable properties after being subjected to high temperature and pressure was unusual as compared with presently used fluids. Therefore, investigation into why these fluids were capable of exhibiting good rheology and fluid-loss control was conducted. It was found that certain mineralogical components of the drilling fluid undergo transformation after being subjected to high temperatures and pressures. The conversion is temperature dependent but also is affected by the presence of various salts as well as the presence of silica and calcium.

The fluids under investigation contained the mineral sepiolite as the basic ingredient. The changes in the sepiolite are reported in this paper.
Capturing Reservoir Behavior by Simulating Vertical Fracture and Super-K Zones in the Ghawar Field
Authors: Phelps Robert E. , Strauss Jonathan P.
Published: December 2007

A dynamic simulation model containing several million cells shows geological details used to simulate the vertical fractures and high stratiform permeability of the Ghawar field. Observed performance data have shown that well intersections in the Ghawar field exhibit thin intervals of extremely high productivity. These can be related to high-permeability layers (stratiform features) or to subvertical faults and fractures. To capture observed field behavior in a dynamic simulation model, these two features must be incorporated in the simulation model. This paper discusses how vertical fractures and high stratiform permeability were simulated in the world's largest oil reservoir.
A Comparison of Caustic Soda and Soda Ash as Chemical Media for SO2 Recovery in Oilfield Steam Generators
Authors: Reyes R.B. , Siemak J.B.
Published: December 2007

Caustic soda and soda ash were used as alkalinity sources in the liquid scrubbing of SO2 in flue gases produced from crude-oil-fired steam generators used in thermally enhanced oil recovery. Caustic soda was used more efficiently, allowing the SO2 scrubber to run at a lower pH with a higher SO2 removal capacity. Overall economics favored the use of caustic soda over soda ash.

Introduction

This study compares caustic soda with soda ash for scrubbing sulfur dioxide in flue gas streams from stream generators used in thermally enhanced oil recovery. The data apply to many other applications as well. Reaction products were measured, and the scrubber chemistry was identified. Mass balances were made by varying chemical feed rates to determine SO2 recovery efficiencies and economics.While distinct differences were observed between caustic soda and soda ash, both the SO2 recovery and the economics favor the use of caustic soda, even though its cost per pound is greater. This is attributable primarily to differences in chemical-reaction kinetics and handling characteristics of the two chemicals.

Scrubber Chemistry

On a purely stoichiometric basis, 1 lbm caustic soda is equivalent in alkalinity to 1.33 lbm soda ash. However, observed chemical consumption rates are nonstoichiometric. In reality, more than 2 lbm soda ash are necessary to do the job of 1 lbm caustic. To understand this phenomenon, scrubber chemistry must be analyzed.

Reactions in a system using a aqueous medium to scrub SO2 from flue gases, alkali must be added to maintain the desired degree of SO2 removal. At the point of alkali addition, several reactions can occur, depending on which alkali is used. A simplified overview of these reactions would be

NaOHSO2 ---- Na2SO3, NaHSO3,....................(1)

and

Na3CO3SO2-------- Na2SO3, NaHSO3, CO2.............(2)

In reality, the chemistry and much more complex. The actual scrubbing, or SO2 removal, is carried out with ionic species formed from the above highly soluble sodium salts.The chemistry of scrubbing and the ionic species present depend on which alkali is used. Once the present depend on which alkali is used. Once the alkali enters the scrubbing system, it reacts quickly according to Ionic Reactions 3 or 4, depending on whether caustic soda or soda ash is used:

Caustic Soda OH + HSO3 ----------->SO3 = + H20.......(3)

Soda AshCO3 =+2HSO3 ----------->2SO3 = +CO2 ......(4)

JPT

P. 751
Linear Aquifer Behavior
Authors: Nabor G.W. , Barham R.H.
Published: December 2007

Introduction

Linear aquifers, either limited or essentially infinite, may be encountered in reservoir engineering practice. In areas where faulting fixes reservoir boundaries, the fault block reservoir may have an aquifer of limited extent whose geometry is best approximated as linear. An infinite linear aquifer can occur as a regional feature whenever water movement through the aquifer member is constrained to one direction. Such constraints can arise from major faults. facies changes or pinchout of the member.

Miller* pointed out that linear aquifers have received only meager attention in the past. He analyzed the performance of finite and infinite aquifers, developed working equations and curves, and presented examples. While Miller's curves may be used fairly easily, a separate one is required for each size of aquifer. In this paper, Miller's equations have been used as a starting point. By modifying them slightly, they can be reduced to a form which yields a single a working curve, applicable to any size of aquifer. Thus, interpolation between curves is eliminated and accuracy is improved.

Miller's results for finite aquifers covered only the boundary condition of no flow across the outer aquifer boundary. This paper also includes the case of constant pressure at the outer aquifer boundary.

DEVELOPMENT OF EQUATIONS FOR LINEAR AQUIFERS

Miller's equations give pressure drop or cumulative influx at the linear aquifer-reservoir boundary as a function of time for the boundary conditions of an infinite aquifer and a finite aquifer with sealed outer boundary. In addition to these equations, those appropriate for the boundary condition of a finite aquifer with constant pressure at the outer boundary have been developed. The approach used in developing these equations was the same as that used by Miller.

BOUNDARY CONDITION 1: CONSTANT RATE OF INFLUX ACROSS AQUIFER-RESERVOIR BOUNDARY

Infinite Linear Aquifer

(1)

Finite Linear Aquifer, Constant Pressure at Outer Boundary

(2)

BOUNDARY CONDITION 2: CONSTANT PRESSURE AT AQUIFER-RESERVOIR BOUNDARY

Infinite Linear Aquifer

(4)

Finite Linear Aquifer, Sealed Outer Boundary

(5)

Finite Linear Aquifer, Constant Pressure at Outer Boundary

(6)

These equations are usually put in a form where dimensionless time is defined by

(7)

Here, x is a reference distance and is usually taken to be a unit distance. However, the choice is really arbitrary, as long as consistency is maintained. We choose x = L; then

(8)

For finite aquifers, L is the length of aquifer; for infinite cases, it may be considered as an arbitrarily chosen length. The reason for this choice will be clear later when the performances of finite and infinite aquifers are compared.

JPT

P. 561ˆ
Integrated Fractured Reservoir Characterization: A Case Study in a North Africa Field
Authors: Gauthier B.D.M. , Garcia M. , Daniel J.-M.
Published: December 2007

In fractured reservoirs, data directly related to fractures are scarce and 1D (e.g., core and image-log data). Other types of data are more widespread (e.g., seismic data) but generally are related only indirectly to fracture distribution. In such reservoirs, it is necessary to understand and then to model the fracture network on a field-wide scale by integrating all available data.

We propose a methodology to achieve this objective. The methodology establishes relationships between the fracturing and other sources of data in a systematic workflow that goes from static 1D data to a 3D dynamic model. The methodology is described and illustrated with a case study from north Africa. In this field, fracture data from image logs and cores are related to (1) 3D seismic attributes (e.g., amplitude, coherency), (2) fault patterns, and (3) other types of well data (e.g., interval thickness, lithology index, and porosity). Production data also are used to quantify the contribution of each fracture set to flow, which then can be mapped on a reservoir basis with the more widely distributed log and seismic data. The resultant set of maps then is entered into a dynamic reservoir model. The methodology has been validated with a new well, the fracture network of which was accurately predicted in the reservoir by the model.
Active Feedback Control as a Solution to Severe Slugging
Authors: Havre Kjetil , Dalsmo Morten
Published: December 2007

Severe slugging in multiphase pipelines can cause serious and troublesome operational problems for downstream receiving production facilities. Recent results demonstrating the feasibility and the potential of applying dynamic feedback control to unstable multiphase flow like severe slugging and casing heading have been published.1–5 This paper summarizes our findings on terrain-induced slug flow.5 Results from field tests as well as those from dynamic multiphase flow simulations are presented. The simulations were performed with the pipeline code OLGA2000.*

The controllers applied to all of these cases aim to stabilize the flow conditions by applying feedback control rather than coping with slug flow in the downstream processing unit. The results from simulations with feedback control show stable process conditions at both the pipeline inlet and outlet in all cases, whereas without control, severe slug flow is experienced. Pipeline profile plots of the liquid volume fraction through a typical slug flow cycle are compared against corresponding plots with feedback control applied. The comparison is used to justify the internal stability of the pipeline. In many cases, feedback control enables a reduced pipeline inlet pressure, which, again, means an increased production rate.

This paper summarizes the experience gained with active feedback control applied to severe slugging. The focus is on extracting similarities and differences between the cases. The main contribution is demonstrating that dynamic feedback control can be a solution to the severe slugging problem.
Analysis of Shallow Gas Development From Low-Permeability Reservoirs of Late Cretaceous Age, Bowdoin Dome Area
Authors: Nydegger Gary L. , Rice Dudley D. , Brown Charles A.
Published: December 2007

Natural gas is being developed and produced in the Bowdoin Dome area from shallow, low-pressure, low-permeability reservoirs that were previously noncommercial. Reservoirs are dominantly thin, discontinuous, shaly siltstone and sandstone laminae and beds which cannot be distinguished on conventional logs. They require stimulation to provide commercial flow rates and necessitate more sophisticated evaluation methods than do conventional reservoirs.

Introduction

This paper reviews the geologic, technological, and economic parameters that have contributed to the development of natural gas reserves in the recently expanded portions of the Bowdoin Dome area. The technology and methods discussed are those used by Midlands Gas Corp., a subsidiary of Kansas-Nebraska Natural Gas Co. Inc, and may differ from those of other operators in the area. The Bowdoin Dome is a very large structural uplift located in eastern Phillips and western Valley counties in north-central Montana (Fig. 1). Natural gas was first discovered on the structure in 1913 in a shallow well drilled for water. The central part of the structure was developed through the 1950's with natural openhole completions in wells drilled where the pay zones are shallower. With the advent of improved completion techniques and increased gas prices in the 1970's, the field was expanded in size to more than 600 sq miles (1550 km2). Natural gas is being produced from low-permeability, low-pressure reservoirs at depths less than 2,000 ft (610 m). The pay zones consist of thin, discontinuous laminae and beds of siltstone and sandstone, and a more persistent limestone bed. These beds are enclosed in a thick sequence of offshore marine shale of late Cretaceous age. The gas is of biogenic origin and was generated in the surrounding marine shales. One major problem existed with the most recent expansion. The development program was designed to be run concurrently with the construction of a large gathering facility. The purpose was to increase economic viability and to develop a more efficient optimization of stimulation techniques and spacing criteria. However, delays in the approval of the pipeline facility forced the operators to use technology evolved in other areas. Specifically, the development of similar shallow gas accumulations in southeastern Alberta was used as an analog for the original treatment designs and 640-acre (2.6 x 10(6) m2) spacing. Most of the development in the Bowdoin Dome area was completed before the final construction of a gathering facility. Therefore, information on the adequacy of the initial development design has become available only recently.

Structure

The Bowdoin Dome is a very large, nearly oval arch which has structural closure of about 700 ft (200 m) on top of the Upper Cretaceous Greenhorn lime. Most of the new development concentrates on a north/northwest-trending nose that extends across the Canadian border.
Convection, Dispersion, and Adsorption of Surfactants in Porous Media
Authors: Ramirez W. Fred , Shuler Patrick J. , Francois Friedman
Published: December 2007

Using the theory of volume averaging, we have shown1 that molecular diffusion, mass tortuosity, and mechanical mixing contribute to the mass-dispersion coefficient. A series of experiments were conducted on the system Triton X-100TM surfactant, n-decane oil, and water to determine the contribution of each mechanism to the total-dispersion matrix for flow through fired Berea sandstone. The dynamics of adsorption and the effect of dead-space volume are considered for the single-phase transport of surfactant through fired Berea. A new dynamic asdorption model is developed which considers both mass transfer to the fluid/solid surface and a kinetic surface-adsorption mechanism. Both kinetic adsorption and mass-transfer rate mechanisms are shown to be important over a wide range of injection rates.