bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Service: Impact of Wellsite Monitoring on Economics, Standards, Performance, and Culture
Authors: Newman Fred M. , Dillingham Don , Ivanhoe Karl 
Published: December 2007

Summary
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

SummaryIn 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

Summary
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

Summary
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 &gt;&lt; 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

Summary
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

Summary
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

SummaryIn 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

Summary
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

SummaryThe 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

SummaryComputer 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

Summary
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

Abstract
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.