bluuebunny/crossref_metadata_2025 huggingface dataset:
Mathematical Description of Spatial Configuration of Deviated Wells and A New Approach to Calculate Borehole Curvature
Authors: Shi Xingquan , Gong Wei'an
Published: December 2007

This paper firstly describes the spatial trajectory of a deviated well using three-parameter equation, then introduces a new approach to calculate the borehole curvature and torsion based on differential geometry. Finally, the approximation of Lubinski formula is demonstrated. Conclusions from this article can be valuable in guiding the in-situ drilling operation.

P. 279
Drilling and Completion Technique of Paired Horizontal Wells
Authors: Hu Suning , Liao Xuehua , Song Jinshi , Liao Runkang
Published: December 2007

A pair of horizontal wells have been drilled in Du 84 Block of Liaohe oilfield. Their well depths are 1214m and 1189m respectively with vertical depths of 769.81m and 760.51m, horizontal section length of 325.53m and 307.71m respectively. The maximum vertical interval for the two horizontal sections is 11 .98m, and the minimum vertical interval is 1 0.43m. The maximum lateral offset to left is 1 .42m, and the maximum lateral offset to right of 0.47m. Two technical casings are run to the window position in both wells, and horizontal sections are completed by hanging 168mm TBS screen pipes.

P. 393
Application Results and Understanding of Several Problems of Industrial Scale Polymer Flooding in Daqing Oil Field
Authors: Wang Demin , Liu Heng , Niu Jingang , Chen Fuming
Published: December 2007

This paper introduces the scale and production results of six industrial scale polymer flood areas conducted in Daqing oil field, since the large scale application of polymer flooding in 1995. Some important technology problems related to the drawing up of polymer flood development projects will be discussed in greater detail. By discussion of these problems, the following conclusions are obtained: the ultimate production results of polymer flooding are closely related to the injection parameters and injection production methods. In order to get better production results of polymer flooding, optimum injection parameters and suitable injection-production methods must be chosen. ln the meantime, by discussion of these problems, it is shown how to optimize the suitable injection parameters and injection-production methods of polymer flooding when the polymer flooding development project is designed.

P. 477
High Temperature Polymer Flooding in Thick Reservoir in ShuangHe Oilfield
Authors: He Jinsong , Song ZhenYu , Qiu Ling , Xie Feng , Tan ZhongLiang , Yue QingShang , Li XiuNing
Published: December 2007

Shuanghe oilfield is characterized by high temperature, serious heterogeneity and thick reservoir. This paper firstly describes the fine characterization techniques of thick reservoir, including geologic features, microfacies of sedimentation, heterogeneity and hydrodynamic unit analysis, and then introduces the study of thermal-oxidative stability of polymers by adding stabilizers. Finally it summarizes the optimized design and effectiveness of high-temperature (72 C) polymer flooding pilot test in layer II 5, Shuanghe oilfield, where oil recovery is increased by 10.4%.

P. 533
Diagnostic Process Enhances Gas Storage Deliverability–A Case Study
Authors: Blauch Matthew E. , Squire Ken , Guoynes John , Jestes Chad , Loghry Ray , Ford William G. F. , Durey Daniel , Frame Russ , Yater John
Published: December 2007

This paper describes a new diagnostic process that can be applied to gas-storage wells. This technique consists of identifying damage mechanisms and designing individual treatments for each mechanism.

The damage identification portion of the new process involves integrating (1) borehole imaging, (2) downhole sampling, (3) well testing, (4) laboratory analyses, (5) reservoir evaluation, and (6) reviews of well and field histories. This part of the process is partially based on results from a previous formation-damage identification study funded by the Gas Research Institute (GRI).1

Two case studies are provided. Based on overall economic results, field deliverability enhancement projects featuring the new diagnostic process have greater gas deliverability potential than conventionally treated wells. The two case studies presented were performed in porous-media gas-storage fields. Case Study 1 (Page 3) was performed on a pressure-drive carbonate reservoir. Case Study 2 (Page 4) was performed on a water-drive clastic reservoir.
Gas Pipeline Network Analysis Using an Analytical Steady-State Flow Equation
Authors: Zhou Junyang , Adewumi Michael A.
Published: December 2007

Zhou and Adewumi proposed an analytical flow equation (ZA model) for steady-state flow through pipelines without neglecting any terms in the momentum equation. In the present study, the linear theory method (LTM) is utilized to solve the network equations based on the ZA model. Some programming strategies are also addressed. A field network with 21 pipes and 16 nodes is simulated using the model, and the simulation results are compared with the field data as well as those obtained using Weymouth equation, Panhandle-A and Panhandle-B equations, respectively.
Application of Advanced Stimulation Technologies in the Appalachian Basin: Field Case Study of Well Performance Several Years Later
Authors: Fairchild Nelson R. , Williamson Jeron R.
Published: December 2007

From December 1993 through October 1996 the Gas Research Institute (GRI) and several local producers were involved in field case studies which applied Advanced Stimulation Technologies (AST). The objective of the studies was to demonstrate new and emerging technologies that would help the operators optimize hydraulic fracture treatment design, execution, and evaluation. The technologies were demonstrated by applying them to wells (study wells) in the areas of interest. The technologies demonstrated included coring, special logging, pre- and post-fracture welltesting, production data analysis,1 in-situ stress profiling,2,3 3D hydraulic fracture design, real-time fracture diagnostics4, and quality control (QC).5 For each study, a benefits analysis was performed by comparing production from the study wells to offset well production to determine if the application of the technologies was beneficial to the operators. All the studies showed some economic benefit to the operator in the form of increased production, reduced treatment costs, or a combination of both.
Modeling of Well Productivity in Perforated Completions
Authors: Dogulu Y. S.
Published: December 2007

Well productivity is the major factor which determines the economic outcome of a well. It depends on the degree of communication between the wellbore and the producing formation. Most oil and gas wells in the petroleum industry today are completed with a steel casing and cement to control the water influx and production from different zones. In these wells communication with the formation is re-established through perforations, usually created by firing shaped charges. The productivity of the resulting completion depends on design variables like shot density, penetration depth and phasing angle.

Previous attempts to calculate productivity in perforated completions suffer from built-in assumptions that require cylindrical symmetry in the reservoir and equal penetration depths for all perforations. This makes the models difficult to interpret in practical situations and inapplicable to horizontal wells in thin production intervals.

This paper describes an improved numerical model to estimate the productivity of a perforated completion as a function of these perforating parameters. Unequal penetration depth, arbitrary phasing angle and shot density can be specified using a flexible algebraic grid generation technique. The near-wellbore grid is also coupled to a coarse-block reservoir simulator which allows different perforating designs to be exercised depending on the relative location of the wellbore (horizontal or vertical) with respect to the reservoir boundaries.

The model demonstrated a good agreement with the existing models for equal penetration cases. Not a significant difference was observed in the productivity results of unequal penetration cases compared to equal penetration productivity results. Anisotropic runs showed lower productivity ratios compared to the existing models. The near-wellbore productivity model coupled with a reservoir simulator is a very useful tool for designing perforating jobs in thin formations with horizontal and slanted wells.
Enhancing Unconventional Gas Development Economics through Proppant Surface Modification
Authors: Blauch Matthew E. , Morrison William K. , Wilkinson John G. , Minthorn Jim , Terracina John
Published: December 2007

A new proppant-pack technology is enhancing incremental gas recovery and estimated ultimate recovery (EUR) of unconventional methane gas in the Northern Michigan Antrim production area. This new technology has enhanced project economics in both restimulation and new-drill applications. Over time, these new technology applications that have evolved in the Antrim play, have resulted in investment-capital infusion and have encouraged development, which has capitalized on development strategies that implement new technology.

The new proppant-pack technology uses a liquid surface-modification agent (SMA) that is applied to proppant on-the-fly during a hydraulic fracture-stimulation treatment. This process coats individual proppant grains with a "tacky" surface, causing the proppant grains to cluster and create a network of loosely packed grains with interconnected clusters. The result is a pliable, but consolidated, proppant pack. The proppant pack also contains conduits, but its adhesive nature increases proppant resistance to post-fracture migration toward the wellbore. The modified proppant grain surfaces enhance the dewatering process by promoting the flow of aqueous fluids and entrapping potentially damaging fines on grain surfaces rather than in pore constrictions.

This paper compares SMA restimulation technology to newly drilled wells on a project basis. Production enhancement results (based on individual well response and impact on total project production response) show that production results are important at both the project and individual well scale.

When compared to the population of conventionally treated wells, newly drilled completions that received the new SMA technology modified the probability distribution of well production. Restimulation was economical on a payout basis and converted gas-in-place to recoverable reserves, enhancing the economics of lower production-class wells.
Mechanical Damage Caused by Perforations May Affect Fracture Breakdown
Authors: Halleck P. M. , Robins J. , Pekot L. , Schatz J. , Schatz John F.
Published: December 2007

We have performed perforation tests on three large rock specimens and mapped indentation hardness around the perforation. We find reduced hardness up to 1.5 inches from the center of the perforation. Maximum reductions as high as 75% occur near the wall of the perforation. In Berea Sandstone, there is a clear trend towards increasing damage near the entrance hole and reduced damage near the perforation tip. On the assumption that the indentation hardness represents more fundamental mechanical properties, a trial elastic model has been developed that illustrates the potential effect of the observed damage on stress distribution, and thus on fracture breakdown pressure. Based on the experimental results, this model predicts incipient fracture initiation at lower pressures, but also predicts high compressive stresses near the boundary of the damaged and undamaged material. This may be interpreted as representing a barrier to further crack extension, thus increasing the effective breakdown pressure. Preliminary, but more detailed computer calculations including wellbore and perforation flow suggest that the damage zone effect can be substantial in restricting ultimate breakdown. It is noted that the actual mechanical model should include brittle and plastic failure to more accurately predict breakdown behavior.
Desorption Enhancement in Fracture-Stimulated Coalbed Methane Wells
Authors: Lehman Lyle V. , Blauch Matthew E. , Robert Lavelle M.
Published: December 2007

The dewatering process, which stimulates gas desorption, is essential for gas production in coalbed methane (CBM) reservoirs. Many CBM wells require hydraulic fracturing to provide interconnectivity and hydraulic access to the cleat/matrix system. Without hydraulic communication and access to the hierar-chical flowpath, gas desorption is severely limited or nonexistent.

When economics allow operators to continue long-term gas production, the gas rate of most coalbed wells will eventually increase. Over time, gas desorbs from the coal macerals that form the cleat blocks. However, some coalbed fields experience premature or severe declines in production because of poor hydraulic-fracture conductivity. Particulates have been discovered as a primary cause of poor hydraulic-fracture conductivity. These particulates flow with produced water; they are then deposited within the proppant pack where they block pore throats and interfere with gas desorption.

A surface modification agent (SMA) that prevents or reduces hydraulic-fracture conductivity damage has been developed and successfully field-tested. This agent, which has strong adhesive properties, helps delay or prevent conductivity damage to the proppant bed. This paper discusses (1) the problems associated with poor hydraulic-fracture conductivity, (2) why it occurs in coalbed wells, and (3) how a new SMA can minimize the problem.
Field Applications of Advanced Stimulation Technologies in Deep and Hot Wells in Dagang Oilfield, China – Diagnostic Tests Made Fracturing Treatments Successful
Authors: Xiong Hongjie , Green Trent W. , Guo Xiuting , Wang Mary
Published: December 2007

Careful review of reservoir data, proppant data, fracture fluid data, and fracturing equipment resulted in the successful application of advanced stimulation technologies (AST)1 such as minifracs, step-down rate tests, and quality control measures in two deep [±3660m (±12,000 ft)] hot wells [150°C (±300°F)] in China. Neither well produced prior to stimulation. Using locally available fracturing equipment and Dagang Oil Co.'s sole fracture fluid system, we successfully designed and pumped two fracture treatments. One well is producing 40 m3/day (250 STB/D) oil and 12,036 m3/day (425 Mscf/D) after stimulation.

This paper describes the AST program implemented by Dagang and summarizes a general methodology for applying new technologies (AST) in new or frontier areas.
Virtual Magnetic Imaging Logs: Generation of Synthetic MRI Logs from Conventional Well Logs
Authors: Mohaghegh S. , Richardson M. , Ameri S.
Published: December 2007

MRI logs are well logs that use nuclear magnetic resonance to accurately measure free fluid, irreducible water (MBVI), and effective porosity (MPHI). Permeability is then calculated using a mathematical function that incorporates these measured properties. This paper describes the methodology developed to generate synthetic Magnetic Resonance Imaging logs using data obtained by conventional well logs such as SP, Gamma Ray, Caliper, and Resistivity. The synthetically generated logs are named Virtual Magnetic Imaging Logs or "VMRI" logs for short.

This methodology incorporates artificial neural networks as its main tool. Virtual MRI logs for irreducible water saturation (MBVI) and effective porosity (MPHI) as well as permeability (MPERM) were generated for four wells. These wells are located in East Texas, Gulf of Mexico, Utah, and New Mexico. The results are quite encouraging.

It is shown that MPHI, MBVI, and MPERM logs can be generated with a high degree of accuracy. For each case, 30% of the data were used to develop the neural model. The model was then tested on the remaining 70% of the data for verification. The models provide VMRI logs with approximately 80 to 97 percent accuracy using data not employed during model development.

This methodology does not supersede the need for performing MRI logging in a field. It is designed to supplement the process by reducing the cost of using MRI logging on an entire field. The natural application of this process is in fields that have conventional logs for all of the wells but MRI logs for only a few wells. To generate the Virtual MRI logs for every well in a field, data from wells that have both conventional and MRI logs are used in the model development and verification. The model is then applied to the other wells in the field to generate the virtual MRI logs for these wells.

Using this process, the operator can log a few strategically chosen wells using physical MRI tools and produce virtual MRI logs for the entire field. This will allow the development of an accurate representation of effective porosity, free fluid, irreducible water saturation, and permeability for the entire field.
Candidate Selection for Stimulation of Gas Storage Wells Using Available Data With Neural Networks and Genetic Algorithms
Authors: Mohaghegh S. , Platon V. , Ameri S.
Published: December 2007

The methodology developed in this study uses several artificial neural networks and genetic algorithm routines to help engineers select restimulation candidates based on available data. The neural networks provide realistic models of the hydraulic frac jobs and chemical treatments in this field. The genetic algorithms provide design optimization and economic analysis (capital investment allocation).

Historically wells in this storage field have been stimulated/restimulated by hydraulic fracturing or by being chemically treated using one, two or sometimes three different chemicals. Several neural network models were developed for different stimulation processes. The first series of genetic algorithm routines are used with each of the neural network models to provide optimum treatment design for each of the stimulation processes. A separate genetic algorithm uses several economic parameters and provides the engineer with an optimum stimulation combination of the candidate wells.

A software tool based on this methodology has been developed for a gas storage field in Ohio.

Upon the completion of the analysis, the software tool provides a list of the maximum number of candidate wells. This maximum number is based on the provided stimulation budget for a particular year. The list specifies the type of stimulation for each candidate well – whether it should be refraced or chemically stimulated – and recommends a list of possible parameters to be used during the implementation.
A Shock-Free Approach in Fractional Flow Theory
Authors: Malik Mohammad A.
Published: December 2007

The Buckley-Leverett solution to the one-dimensional, two-phase, incompressible, immiscible fluid displacement problem in permeable media forms the basis of fractional flow theory. In cases with S-shaped fractional flow curves, the problem of triple saturations is resolved by shock assumption. The Welge integration is then applied for recovery and frontal-advance calculations.

We present an alternative approach in fractional flow theory in which the two-phase displacement problem is analyzed without invoking the shock assumption. The shock-free approach eliminates the triple-saturation problem and identifies that saturation velocities are time dependent.

The shock-free solution is realistic and remarkably dynamic. It results in a simple procedure for recovery and frontal-advance calculations. It provides new insights into the fluid displacement problem by helping to better understand mechanisms that trigger fingering and cause dissipation.
Prediction of Contact Force for Drill Pipe/Coiled Tubing
Authors: Qiu Weiyong
Published: December 2007

This paper systematically presents an approach for predicting the contact force for drill pipe/coiled tubing in vertical, deviated, and curved wells corresponding to different pipe configurations, i.e., no-buckled, sinusoidal, and helical configurations. Utilizing the Lagrange multiplier method, the equilibrium equations are obtained for pipe in vertical, deviated, and curved wells. The Lagrange multiplier represents the unit lateral contact force between the pipe and the wellbore. Solving the equilibrium equations simultaneously, the contact forces corresponding to straight, sinusoidal, and helical configurations are derived for drill pipe/coiled tubing in vertical, deviated, and curved wells, respectively.
Environment and Coiled Tubing: Both Can Be Protected
Authors: Metcalf Arthur Steven
Published: December 2007

Acid stimulation using coiled tubing conveyance is becoming commonplace; however, protection of these coils from acid corrosion is challenging. Add to this the requirement for usage of materials less damaging to the environment, and the task approaches the impossible at high temperatures (>250) and high acid strengths (>20).

The common requirement of corrosion weight loss for jointed tubulars (N-80, J-55, L-80, CR-13, etc.) is <0.05 pounds per square foot and <0.02 to <0.03 for coiled tubing. Increasing acid strength and/or temperature causes an increase in the corrosion inhibitor package cost by nearly 400% as the conveyance tubular changes from N-80 to coiled tubing.

Included in this paper is a comparison of corrosion data generated for hydrochloric acid systems from 20 to 28% on coiled tubing, N-80 and CR-13. The inhibitor evaluated is a blend of select solvents, activated ketone, a small quantity of acetylenics, surfactant and an amine. This material is given a Group "C" designation under the Revised Offshore Chemical Notification Scheme. A summary of the information used to define this inhibitor's Group "C" designation is presented.
An Unexpected Paraffin Dispersant
Authors: Voss M. S. , Cioletti K. R. , Deffeyes K. S.
Published: December 2007

A formulation originally developed for removing ink from printing presses turns out to be a suprisingly successful dispersant for paraffin and asphalt. The formulation is nontoxic and refineries are accepting crude oil produced during the treatment. Laboratory results suggest that the formulation is a freezing point depressant for paraffin not a kinetic inhibitor of paraffin crystallization.
Drilling And Production Techniques In Geothermal Reservoirs
Authors: Whiting Robert L.
Published: December 2007

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

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.

The general types of geothermal systems will be defined and the appropriate rock, fluid, pressure and temperature conditions characterizing each type of geothermal reservoir will be identified. These characteristics will be related to the drilling and production problems which are encountered and the present state of the art of pertaining to the solution of these problems.

Introduction

The population explosion coupled with man's accelerating desire for a higher standard of living has greatly increased his demand for energy in the past, and there is evidence to expect a similar—if nor greater— demand in the future. Quite obviously, natural forms of energy that are readily available at low development cost are those in greatest demand. One of the least expensive energy sources is natural geothermal steam. Although this form of energy has been recognized for centuries, it has been only during the past 20 years that serious efforts have been made to harness it. Natural geothermal steam is now being produced through wells to drive turbines and generate electricity. Identification of geopressured resources has stimulated multiple use development in producing electrical energy, desalinated water, minerals, dissolved gases, etc. The present energy crisis in the U.S. has further accelerated interest in this potential form of energy. Recent development of the Nation's geothermal resources has focused attention on reservoir evaluation and drilling and fluid production problems. It is the purpose of this paper to problems. It is the purpose of this paper to identify these problems and success in their solution, thus far.

RESERVOIR CHARACTERISTICS

Although geothermal reservoir geology has not been satisfactorily described, it is generally agreed that the geothermal fluid is contained in the porous and permeable matrix rock comprising a structural trap having an impervious cap. The geothermal fluid may exist in the reservoir in the vapor, vaporliquid, or liquid state depending upon the pressure, temperature and fluid composition. pressure, temperature and fluid composition. The matrix rock may be of either the isotropic (intergranular) or fracture type or a combination of the two types.
Technical and Operational Factors Crucial to Successfully Drilling Deep Exploratory Wells
Authors: Kandle Joseph R.
Published: December 2007

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

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.

This paper considers deep exploratory drilling from inception through casing design, programming, drilling operations, and programming, drilling operations, and evaluation In each area, the major technical and operational pitfalls that an operator can expect to encounter are discussed along with appropriate recommendations or considerations. Although there is a specific occasional reference to Great Basins - Tenneco 31X-10, Kern County, Calif. (T.D. 21,640 ft, California's deepest) and the basic experience is gleaned from California operations, the majority of recommendations and considerations offered would have application wherever a deep, exploratory well is proposed.

Introduction

Deep drilling operations below 15,000 ft continue to capture the majority of drilling publicity. This voluminous amount of 15,000+ publicity. This voluminous amount of 15,000+ literature deals, for the most part, with the general over-all success of a specific project. Rarely are the everyday field operational and specific technical pitfalls that an operator can encounter in venturing into a project ever delineated. It is the author's opinion that this broad-based successful trending literature has lauded many persons in the petroleum industry into believing that, since deep drilling has extended to the 31,441-ft depth, major technical and operational pitfalls to this depth have been solved; such is not the case, as those in both the design and direct 24-hour field management responsibility level can attest to. Daily, wells projected to 15,000 ft + continue to unsuccessfully reach their projected total depths and/or evaluate their "shows." It is the goal of this paper to delineate the everyday operational and technical pitfalls that an operator can encounter in deep drilling, regardless of their area of operation. By highlighting still existing technical and operational limitations, and suggesting certain operational and technical considerations, the expectation is that other operators will be able to minimize their problems, likewise their future expense, with the ultimate result being more wells to solve the problems associated with deep 15,000+ ft wells, and more reserves for an energy-short nation.

WELL PLANNING AND DESIGN

Information and Data Search

Successful deep exploratory drilling begins in the office of the drilling engineer months prior to spudding. prior to spudding.
Analysis of Drilling Strengths in Evaporite Rocks
Authors: Boone D.E.
Published: December 2007

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

This paper was prepared for the Deep Drilling and Production Symposium of the Society of Petroleum Engineers of AIME, to be held in Amarillo, Texas, Sept. 8–10, 1974. 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 publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor 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.

The drilling strength of rock is a finite measurement of crushing resistence similar to compressive strength measured on laboratory specimens. This rock property dictates most of the drillers procedural decisions on a rig. Drilling strength determines which bit is used, the weight and rotary speed applied and mud properties.

A system has been developed that computes drilling strength automatically within seconds after each foot is drilled. A small computer is employed in the system with electronic sensors that determine depth, weight and revolutions on bit and time of drilling each foot. The computer calculates drilling strength then interprets it to provide a porosity and pore pressure provide a porosity and pore pressure log at bit depth.

Applications of the system, worldwide, have demonstrated a remarkable definition of porosity, permeability and pore pressure in permeability and pore pressure in evaporite rocks. Porosity is generally no more than two porosity percent varience with other porosity tools and pore pressure has an accuracy of + .2 ppg. Experience has shown pore pressure transition over several pressure transition over several hundred feet in massive carborates and significant pressure increase across a hard cap only ten feet thick. This has shown that evaporite rocks have pore pressure distribution detectable pore pressure distribution detectable in drilling response.

Introduction

The fear of a blowout and disaster has plagued the oil industry since Captain Lucas had the first one in 1901. Up to about 1965 a driller had the choice of drilling painfully slow with mud heavy enough to control any pressure or running light mud and gambling that abnormal pressure would not be encountered.
Production Case History, Jay Field, Florida
Authors: Maxson R.D.
Published: December 2007

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

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

The Jay Field discovery in June of 1970 paved the way to extensive drilling and paved the way to extensive drilling and production facility activities in the Florida production facility activities in the Florida Panhandle and in south Alabama. Within 3 years, Panhandle and in south Alabama. Within 3 years, 94 wells had been drilled and 10 treating plants had been constructed. The Jay Field is approximately 8 miles long and about 4 miles wide. Recoverable reserves are estimated to be 337 million bbl of oil. This Smackover production contains about 9 mol percent of hydrogen production contains about 9 mol percent of hydrogen sulfide, which presented many technical challenges in view of safety and environmental considerations. The willingness of industry to commit to risk investments allowed a rapid production buildup to 84,000 B/D and the production buildup to 84,000 B/D and the initiation of a 200,000 B/D waterflood at the same time unitization was approved in March 1974.

The paper will highlight the field development history and will include basic reservoir description and drilling information. Emphasis will be placed on facility design and operating considerations for treating sour crude and gas, and sulfur recovery. A brief description of the field waterflood facilities and plans for gas processing will also be included. plans for gas processing will also be included

Introduction

Recent discoveries in the deep, sour Jurassic Trend in northwest Florida and south Alabama have paved the way to extensive drilling and production facility activities. These field development opportunities have presented many technical challenges in view of the safety and environmental considerations. The most significant discovery in this area is the Jay-Little Escambia Creek Field.

Fig. 1 is a map showing the major Jurassic Trend discoveries in the Jay area, which is some 60 miles east of Mobile, Ala., and 35 miles north of Pensacola, Fla. The first discovery of deeper production was the Flomaton Field, immediately production was the Flomaton Field, immediately north of the town of Flomaton, Ala. This field was discovered in 1968, and produces sour gas from the Norphlet sandstone. Exxon discovered the Jay Field in June 1970. The Blackjack Creek Field, southeast of Jay, was discovered by Exxon in Jan. 1972, and 15 wells have now been completed. Production facilities are scheduled for completion in October. The Big Escambia Creek Field, west of the Flomaton Field, was discovered by Mallard Exploration Co. early in 1972. Twenty wells have been completed and production facilities went on stream in July. production facilities went on stream in July.
A Resume of the Drilling Fluids Used on the World's Deepest Well
Authors: McFarland Wayne , Meyer Robert
Published: December 2007

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

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

Introduction

Lone Star Producing Company, Dallas, has set a new depth record, 31,441 feet, on their Bertha Rogers #1, near Burns Flat, Oklahoma. The old record, also held by Lone Star, is 30,050 feet, set on their #1 E. D. Baden in the same general area of Oklahoma.

Since these wells are the first ever to exceed 30,000 feet, they are the trend setters as the industry is forced to probe deeper for hydrocarbon deposits and/or geothermal energy. The knowledge and experience gained on these wells should prove invaluable in the planning of future deep tests.

This paper deals with one facit of the latest well, the drilling fluids. Included is a brief description of the geological characteristics that were expected in this well, a summary of the mud types and problems encountered while drilling, and some discussion of the auxiliary equipment and testing programs that are necessary for maintaining an optimum fluid at all times. It is hoped that from all this, the reader will gain some insight into the details concerned in handling a job of this magnitude, and possibly use this information as an aid possibly use this information as an aid for improvement in the future.

EXPECTED GEOLOGY

As is the case for most wells, the expected geological characteristics for the Rogers were determined from seismic data and offset well information in the same general area. Because of the depth, however, the bottom portion of the well could be classified as a rank wildcat, with the characteristics highly speculative.

The Burns Flat area of Oklahoma overlies part of the Southern flank of the Anadarko Basin. This flank is a steep, block faulted limb, paralleling the Amarillo-Wichita uplift (Fig. 1). The "Anticipated Geological Section" (Fig. 2) gives a better idea of the formations to be penetrated.

The primary target for this well was the Devonian dolomite (Hunton), which was non-commercial in the Baden test.

The sediments of the Anadarko basin are mainly carbonates with mixed layers of sand and shale. However, because of the intense folding, faulting, and uplifting that has taken place along the southern flank of this basin, massive sections of shale and some sand are predominant from about 12,500 feet to in predominant from about 12,500 feet to in excess of 23,000 feet.
A Parallel Multiblock/Multidomain Approach for Reservoir Simulation
Authors: Wheeler Mary F. , Arbogast Todd , Bryant Steven , Eaton Joe , Lu Qin , Peszynska Malgorzata , Yotov Ivan
Published: December 2007

Our approach for parallel multiphysics and multiscale simulation uses two levels of domain decomposition: physical and computational. First, the physical domain is decomposed into subdomains or blocks according to the geometry, geology, and physics/chemistry/biology. Each subdomain represents a single physical system, on a reasonable range of scales, such as a black oil region, a compositional region, a region to one side of a fault, or a near-wellbore region. Second, the computations are decomposed on a parallel machine for efficiency. That is, we use a multiblock or macro-hybrid approach, in which we describe a domain as a union of regions or blocks, and employ an appropriate hierarchical model on each block.

This approach allows one to define grids and computations independently on each block. This local grid structure has many advantages. It allows the most efficient and accurate discretization techniques to be employed in each block. The multiblock structure of the algebraic systems allows for the design and use of efficient domain decomposition solvers and preconditioners. Decomposition into independent blocks offers great flexibility in accommodating the shape of the external boundary, the presence of internal features such as faults and wells, and the need to refine a region of the domain in space or time (by treating it as a distinct block); interfacing structured and unstructured grids; and accommodating various models of multiscale and multiphysical phenomena. The resulting grid is not suited to direct application of discretization methods. We use mortar space techniques to impose physically meaningful, mass conservative, fluxmatching conditions on the interfaces between blocks.

We present numerical simulations to illustrate several of these decomposition strategies, including the coupling of IMPES and fully implicit models and upscaling by varying the number of degrees of freedom on the block interfaces.
Applications of a Parallel Simulator to Industrial Test Cases
Authors: Verdière Sophie , Quettier Lisette , Samier Pierre , Thompson Alan
Published: December 2007

Computer models of oil reservoirs are becoming more and more complex in order to represent the heterogeneity of rock structures more realistically. It is, however, necessary to restrict the resolution of models and the number of components in compositional models because of the limits of computer CPU time and memory. This leads to uncertainties in the simulation due to the averaging techniques used in petrophysics and in the modelling of surface processes.

Parallel computing is now an attractive solution to overcome these drawbacks by using the best of the hardware and software technology.

In this paper, we look at the efficiency of the parallel versions of Eclipse 100 and 300. We evaluate their speed, memory requirements and scalability using black oil and compositional models with up to 16 components on an SGI Origin 2000 with 16 processors. These are based on real fields and range from 100 000 to 4 500 000 cells with cells as small as 20×20×0.5 meters.

We examine the problems of deciding on the decomposition of domains, and the choice of message passing systems. We also discuss the optimal way of managing the job scheduling. We show the difficulties of pre and post processing large data sets and visualizing the results of simulations. The analysis of results of these test cases allowed us to quantify the benefits of a finer geological and fluid description. With the parallel option, we can now envisage the possibility of running weekend jobs overnight and overnight jobs during normal working hours.

We show that the jump of parallel computing from research to industrial applications provides real benefits to engineers.
A Mixed-Wet Hysteretic Relative Permeability and Capillary Pressure Model in a Chemical Compositional Reservoir Simulator
Authors: Delshad M. , Lenhard R. J. , Oostrom Mart , Pope G. A. , Yang S.
Published: December 2007

A crucial component of all multiphase flow models is the relationships among relative permeabilities, fluid saturations, and capillary pressures. Relative permeability and capillary pressure parametric models can be very useful for predicting fluid behavior in porous media. However, relative permeabilities and capillary pressures used in oil reservoir simulators are commonly determined via interpolation between laboratory measurements. A problem with this approach is that the relations are valid only for the specific saturation path measured. Therefore, simulations of oil production using different saturation paths than those measured are likely to be in error and can limit the investigation of alternative production scenarios. In this paper, saturation-history-dependent relative permeability and capillary pressure functions for mixed-wet rocks are discussed. Relative permeabilities are predicted via integrating a pore-distribution model between limits that reflect how oil and water are distributed in mixed-wet porous media. The proposed model was tested against mixed-wet capillary pressure data. The model was then incorporated in the University of Texas Chemical Compositional simulator called UTCHEM to compare waterflood simulations in water- and mixed-wet reservoirs. The simulation results agree qualitatively with laboratory core and field observations. The model and its implementation were also validated against sandpack experiment.
Reservoir Characterization of Ekofisk Field: A Giant, Fractured Chalk Reservoir in the Norwegian North Sea – History Match
Authors: Agarwal B. , Hermansen H. , Sylte J. E. , Thomas L. K.
Published: December 2007

The history match of the 3-D fluid flow model constructed on the Ekofisk Field is the focus of this study. The Ekofisk reservoir is a high porosity, low matrix permeability naturally fractured chalk. Fluid flow is largely governed by the distribution, orientation and interconnectivity of the natural fracture system associated with complex structure and reservoir distribution. Because of the impact heterogeneity has on preferential fluid flow direction, significant attention was given to capturing as much of the intrinsic heterogeneity as possible, both laterally and vertically, in the new 3-D geological model. A fairly high-resolution simulation mesh was defined for the fluid flow model, and a flow-based upscaling technique was then applied to preserve the heterogeneity from the geological to the fluid flow model. Because of the complexity of the Ekofisk Field, with its numerous faults and fracture networks, anisotropy was one of the primary attributes manipulated to achieve an individual well and field history match. However, faults and fault sealing factors, vertical permeability, pseudo relative permeability curves, bubble point pressure correlations, local permeability, and rock compressibility were also key parameters in the history match, and are presented in this paper. A brief discussion on the preliminary implementation of water-induced compaction is included.
A Preconditioned Adaptive Implicit Method for Reservoirs with Surface Facilities
Authors: Byer Thomas J. , Edwards Michael G. , Aziz Khalid
Published: December 2007

Fully implicit coupling of surface facilities with a reservoir model can lead to a significant increase in computing time. The focus of this paper is on methods designed to reduce the computational effort. An adaptive implicit method is coupled with a novel preconditioning method to produce an optimal strategy for fully coupled surface facility reservoir simulation.
Using Boundary Integral Methods to Couple a Semi-analytical Reservoir Flow Model and a Wellbore Flow Model
Authors: Ding Y.
Published: December 2007

Complex wells such as horizontal wells or multi-lateral wells are increasingly used in reservoir engineering to improve the oil recovery. A widely used semi-analytical method to study the behavior of this kind of wells, such as production performances or transient pressure responses is the source function method. However, the source method is only a particular approach to this problem, and it can be improved using boundary integral techniques.

In this paper, a mathematical model, based on the potential theory, is established for transient problem. A boundary integral equation (BIE) is introduced using the single layer heat potential. The finite (pressure drop along the well length) conductivity can be taken into account in this model. So, the wellbore flow model is adequately coupled with the semianalytical reservoir model.

The collocation and Galerkin methods are particularly studied to solve the BIE. It is shown that the Galerkin method is more efficient than the collocation method or the line source method, which can be deduced from the collocation method. Some applications of this model are also presented.
Split Tensor Operators Coupled with Quasi K-Orthogonal Grids
Authors: Edwards Michael G
Published: December 2007

Standard simulators that can only allow for a diagonal tensor routinely perform simulations with O(1) errors in the velocity field whenever a full tensor is present. Two approaches that permit the use of diagonal tensor 2-point flux approximations are either (a) to only employ K-Orthogonal grids or (b) split the full tensor operator. The two methods are coupled together for full tensor simulation and it is shown that the split scheme is a natural candidate for use with K-Orthogonal grids.
A New Particle Tracking Algorithm for Tracer Flow Simulation
Authors: Liu J. , Parker E. D. , Camilleri D.
Published: December 2007

A new particle tracking algorithm has been developed for the general case of irregular grids. Particle velocity magnitudes and directions are determined from interpolations of phase fluid fluxes across cell faces. The interpolation is based on particle coordinates in unit cube space and the edge directions of the cell. Cell transformation functions are used in transforming coordinates between physical space and unit cube space. Transformation parameters and cell edge directions are calculated once at the beginning of the simulation. Special treatments are given to cells with wells or fault connections to take into account their impacts on the particle velocity. A more accurate high-order tracking method is applied where the timestep is subdivided if a particle enters a neighboring cell or reflects during a timestep. The interpolation process then continues for the remainder of the timestep using the new cell data. A dispersion mechanism is included in the model which can be defined as either isotropic or non-isotropic.

The new algorithm has been implemented into our commercial three-dimensional, three-phase reservoir simulator, VIP. This enables the simulation of tracer flow within the framework of three-dimensional, multiphase, unsteady state reservoir simulation. The tracers are non-partitioning, and can be injected at various concentrations with either the gas or water phases. Since the algorithm is applicable for irregular grids, it becomes possible to be applied for field applications that have to use corner point grids to deal with complicated reservoir structure and geometry. The algorithm has been tested and validated on one- and two-dimensional models with analytical solutions and applied to field scale tracer applications. Three-dimensional visualization and animation of the particle paths and fronts has demonstrated the effectiveness of the tracking algorithm.