bluuebunny/crossref_metadata_2025 huggingface dataset:
A Mathematical Model of the Steam Drive Process Applications
Authors: Neuman C.H.
Published: December 2007

This paper was prepared for the 45th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Ventura, Calif., April 2–4, 1975. 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 requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested 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 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

Previously reported calculations of Previously reported calculations of oil displacement by continuous steam injection either ignore the effects of gravity override or simulate them numerically. This paper describes a theoretical analysis of the problem that leads to a relatively simple solution. A steam zone is assumed near the overburden. Calculations include (1) the rates of steam zone thickness increase vs time since steam first arrived, (2) the steam zone areal increase rate, and (3) total oil displaced (from the steam and underlying hot water zones). The mathematical derivation is to be submitted to the SPE Journal.

Equations describing the steam drive process are presented, applied in an process are presented, applied in an example, and discussed as to limits of validity. Predicted and observed steam drive behaviors are compared for Chevron's Ten Pattern Steam Flood in the Kern River Field, California. Also discussed are methods of application for economic and engineering analysis.

OUTLINE OF GRAVITY OVERRIDE MODEL

Steam injected during steam flooding rises to the top of the injection interval, causing the steam zone to grow downward as well as areally. The vertical rate is determined by the rate of steam condensation from heat diffusion into the overburden and the liquid-filled underlying reservoir. The rate of areal growth is determined by the balance between the net energy injected as steam and that required from steam condensation to sustain vertical growth. The amount of oil displaced from below the lower steam interface can be predicted from the temperature profile there and a critical temperature. The latter depends on the flow properties of the reservoir and fluids. The model presented here is like that of Marx and Langenheim in that neither assumes a particular areal geometry.
Design and Operation of a Supercritical CO2 Pipeline-Compression System Sacroc Unit, Scurry County, Texas
Authors: West James M.
Published: December 2007

The SACROC Unit is in the second year of a carbon dioxide miscible flood that is the largest secondary recovery project of this type ever undertaken. To accomplish this flood, over 35 million tons of carbon dioxide will be used for injection into the reservoir. The total cost of the project when finalized will be in excess of $175,000,000. This cost includes purchase of CO2, conversion of over 200 producing wells to CO2 injectors, expansion of surface facilities and the construction and operation of the CO2 Pipeline-compression system. The magnitude and innovative nature of the project has demanded a major engineering, planning and design effort involving the coordination of many fields of engineering and various technical specialties. This paper will give a brief account of the overall CO2 delivery facilities to include the basic design considerations and some of the studies that were conducted for each aspect of the project.

The focal point of the CO2 transport project is the SACROC Unit in Scurry County, Texas. (Referring to Figure No. 1). It might be noted that the name SACROC was derived from the initials of the "Scurry Area Canyon Reef Operators Committee", a task group that was activated for essential work required prior to the formation of the SACROC Unit. The Canyon Reef field was discovered in 1948 with major development beginning in 1949 and extending through 1951. During this period, over 1,000 wells were drilled to develop more than 50,000 acres. The surface extent of the field is about 6 miles wide by 12 miles long.

Waterflood operations were started in 1954. By 1972, over 280 million barrels of oil had been produced by waterflood.
Cementing of Well Casings for Pollution Control
Authors: Runyan E.E.
Published: December 2007

This paper discusses the importance of obtaining a good cement job in well completions, and the three areas vital to obtaining this effective wellbore cement seal. These three areas are (1) formation cement interface (2) casing cement interface, and (3) the cement sheath itself.

An operator is interested in getting best cement job possible for several reasons:shut off and/or protect fresh and salt-water zones,segregate producing zones,eliminate communication between gas-oil, oil-water, or gas-water contacts,stabilize the casing string, andseal well fluids in wellbore to prevent surface or subsurface pollution. prevent surface or subsurface pollution.

The steps involved in obtaining a good wellbore seal are (1) good borehole conditions, (2) good wellbore cleanup prior to cementing, (3) removal of excess filter cake from permeable formations, (4) selection of correct cement composition for given well conditions, (5) proper centralization of the well casing, and proper centralization of the well casing, and (6) preparation of the external casing surface for maximum cement bonding.

Several field case histories are presented to show the effectiveness of proper cementing practices, particularly the effectiveness of practices, particularly the effectiveness of resin-sand coating of the casing in producing an extremely strong bond between cement and casing. The application of the Cement Bond Log for evaluation of the final cement job is also presented. The paper concludes that potential presented. The paper concludes that potential problems of fluid leakage and their consequences problems of fluid leakage and their consequences can be minimized by the proper use of known technology.

Introduction

The cementing of oil, gas, gas storage, injection, and disposal wells throughout the industry has received a great amount of attention over the past 50 years in both research and field development areas. This attention and research is continuing. Probably no other aspect of the completion operation has been as widely studied and discussed. Yet, cementing problems continue. Partially, this is due to problems continue. Partially, this is due to the complexity of the problem, but unfortunately, it is also partly due to failure to properly apply known technology.

The cementing operation is designed to (1) shut off and/or protect fresh and saltwater zones, (2) segregate producing zones, (3) eliminate communication between gas-oil, oil-water, or gas-water contacts, (4) stabilize the casing string, and (5) seal well fluids in the wellbore to prevent environmental contamination.
The first semi-submersible platform specifically designed for dynamic positioning
Authors: Susbielles G. , Martin Y. , Vasseur B.
Published: December 2007

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 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 Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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.

Results are given of a study in which the behaviour of semi-submersible platforms equipped with respectively 2, 3 and 5 floaters is compared under the action of waves, winds and currents. Required conditions were minimum effects of wind and currant action and most favourable amplitude levels for drilling operations.

A three-legged platform turned out to be the best choice. Results of mathematical model studies were complemented and verified with the help of model basin tests. Additional model tests were performed in a wind tunnel to determine the optimum deck shape.

Main features of the installation of drilling equipment on deck will be shown. Information is also given on the dynamic positioning system.

Introduction

The search for new subsea oil and gas fields under greater and greater water depths and the exploration of such fields has led to the replacement of jack-up platforms by floating supports such as drilling ships and semisubmersible platforms.

In addition, consideration must also be given to the effect of extremely hostile environmental conditions (storms) on such structures. A platform must withstand such disturbances at one time or another during its effective life span, depending on the work schedule it must follow. At the same time, new sorts of dangers (icebergs) make it necessary to minimize installation time at a given site and to maintain the possibility of moving away in the midst of a possibility of moving away in the midst of a drilling operation.

Under such conditions, dynamic positioning is of great interest because it guarantees positioning is of great interest because it guarantees quick installation on a drilling site and enables the position to be changed as fast as it becomes necessary as the result of marine elements (i.e. keeping headed into the wind of current if necessary).
Laboratory Investigation of a Suitable Waterflood for the Bulgurdag Field and a Design of a Tracer Field
Authors: Durusu Ilhan
Published: December 2007

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 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 Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 study presents the results of a laboratory investigation of a suitable waterflood tracer for a limestone reservoir such as the Bulgurdag field. For this purpose, continuous and slug injection tests were performed in a crushed limestone pack by using potassium iodide, sodium chloride and potassium iodide, sodium chloride and sodium borate as tracers. Continuous injection tests were performed with various concentration or tracer added to the floodwater. The lengths of the mixing zone for each tracer were thereby obtained. To obtain adsorption losses during propagation, a number of slug injection tests were made in which slugs ranging from 100 to 25 to 10 and to 5 percent of the length of mixing zone percent of the length of mixing zone were injected and displaced by continuous injector of floodwater. On the basis of the laboratory results, it is concluded that because of its adsorption loss and the difficulty of the chemical analysis, sodium borate is not a suitable tracer. Potassium iodide is a suitable tracer when present even very small quantities, but its use is not considered economical due to its high price. The sodium chloride tracer, although the required amount is the largest, is the most economical tracer for use in the Bulgurdag field due to its low price.

A design of a tracer flood for the Bulgurdag field is also proposed. The weight of the tracer chemical and the cost are calculated for various slug sizes. The time at which the tracer will first appear in the production well is predicted on the basis of a presumed reservoir geometry and presumed reservoir geometry and lithology.

Introduction

In the secondary recovery of petroleum by water flooding, an accurate petroleum by water flooding, an accurate evaluation of the subsurface pattern of flow of the injected water is necessary.
Gas Production And Interference Effects
Authors: van Golf-Racht Th.
Published: December 2007

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 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 Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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.

In the interference problem some aspects which have not yet been taken in consideration were examined in this paper. These problems are:How could paper. These problems are:How could the turbulence influence gas well interference tests, andrelationship between producing wells and their distribution.

In the first part of this work it was shown that turbulent flow is influencing the transient behaviour during well interference test, and a method of evaluation was indicated. A calculation example has shown quantitatively the importance of neglecting turbulence effect in interference evaluation. In the second part of the paper the relationship between number paper the relationship between number of producing wells and single well rate as affected by well interference was discussed. The interference concept is usually associated with the idea that an increased number of wells reduces the single well rate or, for maintenance of a constant rate, requires a higher pressure draw-down. It is demonstrated pressure draw-down. It is demonstrated that this conclusion is valid only if the hydrocarbon reserve is in direct contact with an efficient lateral water zone and if the wells are non-uniformly distributed over the structure.
Diffraction of Water on a Body of Revolution Along Several Meridians - Application to a Tank in the Sea
Authors: Le Goulven P. , Alleuard Y. , Coudert J.F. , Lamy Y.
Published: December 2007

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 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 Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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.

It is advantageous for tank or platform builders to be able to calculate platform builders to be able to calculate pressure distribution on a body of any pressure distribution on a body of any shape set on the bottom of floating. This model is an initial approach to the problem. It can be used to calculate pressure problem. It can be used to calculate pressure distribution, total force or moments on a solid of revolution set on the bottom or floating. For this, the fluid is assumed to be perfect, irrotational and non-viscous. We are thus working with linear conditions. The solution is calculated in a functional space of splines in the domain between the body and an arbitrary cylinder encompassing it. The solution is continued outside the cylinder as a Bessel function series.

Introduction

For offshore structures, it appears more and more necessary to be in possession of sufficiently accurate and possession of sufficiently accurate and reliable mathematical models. The existence of very powerful computers such as the CDC 7600, for which this model has been programmed, thus makes it possible to programmed, thus makes it possible to consider methods which, although requiring relatively extensive calculating, give more accurate and complete results than in the past. This study was made for the Association de Recherche "Action des Elements" which we hereby thank for having allocated to us the necessary funds and for authorizing publication.

PHYSICAL HYPOTHESIS PHYSICAL HYPOTHESIS The fluid is assumed to be:

* Irrotational, incompressible, nonviscous.

* The pressure at the free surface is also assumed to be constant.

Under such conditions, there exists a velocity potential phi (x, y, z). So that :

in which u, v, w are the velocities components on x, y and z axis.

One can show 1 that phi thus checks out:

delta phi = 0

which is associated with the Bernoulli's equation :
Foundation Scour And Remedial Measures Foil Offshore Platforms
Authors: Sybert J.H.
Published: December 2007

Five platforms installed near Padre Island in the Gulf of Mexico experienced scour of foundation material caused by strong littoral currents. Dish-shaped depressions were formed under each platform; some were twelve feet deep and the edges extended as far as sixty feet from the platforms. Laboratory research projects directed the design of an inverted filter which was installed at each platform. Design information and installation techniques are given. Submarine surveys following Hurricane Carla in 1961 found a minimum amount of filter material displaced and very little additional scour.

Introduction

The Chevron Field is located in the Gulf of Mexico just offshore from Padre Island. It is approximately 25 miles southeast of Corpus Christi, and is east of Kingsville. Oil and gas wells are being produced from five platforms which are located 1 1/2 to 2 1/2 miles from the shore, where the water is approximately 40 feet deep.

During the installation or these platforms, foundation cores were taken to determine proper pile penetration. Cores could not be recovered from the upper soil layers due to its unconsolidated state; however, it was found that these layers consisted of fine sand with a few shells and a few clay stringers.

Approximately 2 1/2 years after the first platform was installed, divers who were working on a salvage operation reported that the sand had been scoured from beneath one of the platforms. Three platforms were in place at the time and the fourth was being fabricated.
Numerical Simulation of the Solution Mining Process
Authors: Nolen J.S. , von Hantlemann O. , Meister S. , Kleinitz W. , Heiblinger J.
Published: December 2007

A new digital computer program simulates the solution-mining process. This program calculates, as a function of time, the shape of a salt cavern created by the single-well leaching process, the concentration of the produced brine, and the rate of increase of cavern volume.

In this paper the method of simulation is briefly described, as are a special core analysis technique and a method of log interpretation used to prepare data for the simulator. Calculated cavern shapes are compared with field measurements for two caverns leached in a heterogeneous salt formation.

It is concluded that the simulator is capable of accurately calculating the shapes of salt caverns leached in such formations and that core analyses and properly interpreted well logs can provide good estimates of the salt properties necessary for simulation.

INTRODUCTION

Solution mining has long been used to produce NaCl, KCl, and other soluble salts. Now it is being increasingly applied as a method of creating storage for crude oil, natural gas, refinery products, and industrial wastes.

Among the reasons for the great interest in salt-cavern storage are the following: (1)Salt formations are stable within known limitations; therefore, it is possible to construct structurally sound storage caverns for long period of operation.Salt is so impermeable to flow that fluids can be stored in a cavern for long periods without leakage, provided the well is carefully completed.Virtually 100% of storage liquids are recoverable from salt caverns. In high pressure gas caverns the ratio of working gas to cushion gas is high.
Advanced Well Construction as Integral Part of Reservoir Management
Authors: Holm W. H.
Published: December 2007

The continued challenge to increase reserves from producing fields has highlighted the need for further integration of the well construction process into reservoir management.

During the early nineties, the need to reduce costs while improving safety and drilling performance led to a change in Phillips Petroleum Company Norway's approach to drilling management. Despite staffing reductions, changes to engineering and operational philosophy created the foundation for significant improvements in safety, environmental and operational performance.

Faced with a reduction in offshore activities as a consequence of redeveloping the giant Ekofisk Field, a major organizational re-engineering effort was initiated in the spring of 1996. The result was a radically, new organizational model, which emphasizes customer satisfaction and value creation, while maintaining focus on competence building, multi-discipline team work and shared learning (organizational learning).

This paper describes the continued organizational and technological evolution that has enabled Phillips Petroleum Company Norway (PPCoN) to deliver advanced wells, such as horizontal and multilateral wells, with a clear focus on reserves replacement, while making continued progress on safety and cost reductions.
Rig Upgrades and Proper Planning Result in Successful Drilling in Bohai Bay, China
Authors: McRae J. D. , Boudreaux B. A. , Yao Wang Zhen , Hai Yang Yuan
Published: December 2007

This paper describes the pre-planning and execution of Kerr-McGee China Petroleum's Laohai #1 drilling project in Bohai Bay, China. It details our approach in ensuring a safe and efficient drilling program utilizing a Chinese drilling unit that had never worked for a foreign operator nor drilled in a deep, abnormally pressured environment.

The paper will detail the strategies used for implementing rig upgrades, training and working with Chinese National personnel, and improving the well design in order to reduce risk and increase efficiency. It will also describe the operational successes and failures due to these strategies and the improvements made during the well operations. Finally, recommendations for future projects with similar circumstances are presented. This approach will provide valuable insight for a foreign company planning a well using a Chinese drilling unit.
Variation of Skin Damage with Flow Rate Associated with Sand Flow or Stability in Unconsolidated-Sand Reservoirs
Authors: Tippie D.B. , Kohlhaas C.A.
Published: December 2007

Discussion of this paper is invited. Three copied 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.

A semi-cylindrical sand-pack model of a cased-and-perforated completion was loaded with an overburden pressure and fluid flowed through the pack to simulate production. Flow rate was gradually increased in each test. Sand arches formed to stabilize sand movement. As reported previously by the same authors, arch size was a function of flow rate. Skin effect caused by arch formation, destruction, and size variation is also a function of flow rate. Minimum skin effects were noted for a particular flow rate. Potentiometric flow particular flow rate. Potentiometric flow models were used to verify sand-pack results. Flow tests in a linear flow cell indicated a significant damage effect (permeability reduction) due to fines migration. The sand-pack completion model indicated that the fines migration and skin effect change are associated with sand instability.

Introduction

Sand production from oil and gas wells has become a major problem in many regions of the world. A high percentage of current exploration and develonment effort is being expended in these areas. Sand control with plastic injection and gravel packing is not only time-consuming and expensive, but also generally causes severe productivity restriction.

The authors studied flow through a sand pack in the laboratory to understand the natural mechanism which prevents sand production from some wells completed in production from some wells completed in unconsolidated sands. That work was based on the arching studies of Hall and Harrisberger and Stein and Hilchie. Natural stabilization by arching of unconsolidated sand during production was confirmed with a sand pack model of a well completion. Fluid was flowed radially through a semi-cylindrical sand pack which was loaded vertically to 260 psig to simulate overburden pressure. (See Figure 1). Inlet fluid flow was distributed evenly over the outer surface. The inner cylindrical surface represented well casing. Sand used was 20–40 mesh Gopher State proppant sand. Sand arches formed around the fluid outlet ("perforation") to establish static equilibrium between the stressed sand pack and unstressed sand at the perforation. (See Figure 2). perforation. (See Figure 2). Flow rates were increased until sand flowed.
Validation of Wax Deposition Model by a Field Test
Authors: Hsu J. J. C , Lian S. J. , Liu M. , Bi H. X. , Guo C. Z.
Published: December 2007

An accurate prediction of wax deposition profiles along a production line has significant impact on savings, pipeline design, flow assurance and operations of waxy crude production system in oil industry. Validation of wax deposition model by a field test is a necessary step to ensure accuracy of the modeling results.

A field, located in Northeast China, was chosen for the field test. A pipeline was installed between wellhead and original production line. After 18 days of field test, the pipeline was disassembled and cut into 31 pieces. The amount of wax deposition in each piece of pipe was measured and recorded. In the field test pipeline, waxy crude was transported under multiphase flow conditions at temperatures below pour point. The wax deposition model is a semi-empirical model to include molecular diffusion and shear effects. A scaler is proposed for the modeling. The accuracy of this model relies on the accurate experimental data obtained from the special wax-deposition-flow-loop test procedures. The state of art wax deposition flow loop, built in Beijing, China by two oil companies, can accurately and cost effectively determine wax deposition tendency and rheology of waxy crude from temperatures above the oil cloud point to ambient.

A recombined live oil was used in the laboratory flow loop tests. The laboratory data and the field operating conditions were input to the wax deposition model. The modeling results were compared to the field data for validation. The accuracy of the modeling results and modeling technique are discussed in this paper.
Measurement of Dielectric Parameters of Rock Cores at 300 kHz to 3GHz Frequencies
Authors: Nguyen Buu-Long , Bruining Johannes , Slob Evert C.
Published: December 2007

We describe a new experimental setup which enable measurement dielectric response of rock cores at different saturation. The experimental setup combines the well-known steady-state core flooding technique and measurement of the S11 scatter functions.

We derive the equations describing the scatter functions for a multisection coaxial transmission line ended in lossy media. We consider the case when the transmission line contains a coaxial sample holder.

Based on the theoretical model of the scatter function, we developed a procedure for the calculation of the frequency-dependent complex dielectric permittivity of rock cores from the scatter functions.

The complex dielectric permittivity of brines, oil and dry sandstone, as well as complex dielectric permittivity of brine-saturated sandstone, obtained from experimental measurements and numerical optimization process are also presented.

We observed high dielectric losses in brine-saturated sandstone. The effects of brine concentration on dielectric losses are however not significant.
Effects of Shear Planes and Interfacial Slippage on Fracture Growth and Treating Pressures
Authors: Barree R.D. , Winterfeld P.H.
Published: December 2007

The equations used in current hydraulic fracture simulators are based on plane-strain solutions, or use a complete surface integral solution for fracture width. Assumptions inherent in these solutions control the stress field surrounding the fracture tip and the stress intensity developed at the tip which, in turn, controls the rate of fracture growth and containment and the predicted net pressure. The overriding assumption made in these solutions is that the entire rock mass is elastically coupled so that all stresses and deformations interact.

Many reservoirs that are hydraulically fractured are susceptible to complex fracturing which can invalidate the assumption of elastic coupling. Microseismic monitoring of fracture growth indicates that energy is lost to shear failures around the fracture. During hydraulic fracturing high fluid pressures, often exceeding both the minimum and maximum horizontal stress (fissure opening pressure), result in the reduction of the normal stress acting across natural fissures. This allows free shear or slippage along natural fracture planes in reservoirs or cleats in coal. When shear or slippage occurs elastic coupling in the rock mass is lost and each shear block deforms as a separate unit. This shear decoupling results in tremendous reduction in created fracture width and leads to high frictional pressures (low transmissibility) and difficulty in placing proppant, especially large proppant.

The purpose of this work is to suggest that current fracture models are missing what could be a dominant containment mechanism in the fracturing of fissured reservoirs, coals, and soft rocks and that further work is required to fully understand the implications of slippage and shear failure on treatment designs.

P. 11
Significant Production Enhancement of Extended Reach, Prolific Gas Lift Oil Wells -- Case History of Systematic Problem Resolution
Authors: Hahn D. , Yu D. , Tiss M. , Dunn R. , Murphy D.
Published: December 2007

Most oil wells producing from the Glauconite YY Pool of the Lake Newell field in Southern Alberta, Canada have very high flow capacities. Wellbore operations are complicated by the configuration of the slant wells with surface angles of 45 that can reach 75 at bottom and horizontal displacements in excess of 6600 ft. During the development of this field, it was determined that there was a full cycle economic advantage to utilize gas lift as the primary artificial lift scheme because of the extended reach slant wellbore configurations. In 1996 opportunities to economically enhance production and accelerate recovery were identified in several of these gas lifted wells.

Wellbore performance could not be matched to any theoretical tubular flow simulation thus a significant effort was made to understand these differences which, after consultation with various international experts, still did not offer a definitive explanation. Some of the production impairment mechanisms considered were phase separation and stratification of fluids (water, oil, and gas) in the tubing, wax/paraffin formation, and unknown fluid rheologies. An attempt to production log one well was unsuccessful because the well ceased to produce with the decreased flow diameter of coiled tubing inside 2.875 inch production tubing. Since some wells are producing at drawdowns as low as 5%, significant production enhancement opportunities still needed to be pursued along with identifying the welibore production impairment mechanism.

Larger diameter tubing (3.5 inch) was run in a 70% water cut well increasing production from 850 BLPD to 1130 BLPD, which was still significantly lower than theoretical rates of 3150 BLPD. A demulsifier chemical, that the cross functional property team had previously identified as being effective in reducing high pressure drops in surface piping, was introduced into the injection gas stream. Two days after chemical injection began, the well started to produce at theoretically predicted production rates; however, it was very unstable and would cycle to original rates for long periods of time followed by very high rates again due to changing annular fluid levels. This prompted the installation of a chemical injection capillary tubing to bottom resulting in sustained production of 3000 BLPD: a 150% increase and near the theoretically predicted rates.

This paper will sequentially outline the diagnostic and operational methodology used to solve the very difficult problems encountered with unconventional wellbores and fluids. It will emphasize the value of teamwork in problem resolution and demonstrate that perseverance in working through a problem or issue follows a modified Shewhart Cycle. The well improvements outlined in this paper have significantly contributed to enhancing the economic oil recovery of the YY Pool.

P. 67
A Simplified Approach to Couple Wellbore Flow and Reservoir Inflow for Arbitrary Well Configurations
Authors: Ouyang Liang-Biao , Aziz Khalid
Published: December 2007

A wellbore/reservoir flow coupling model is developed. It can be applied to a parallelepiped drainage domain consisting of any number of wells with any number of laterals of arbitrary configurations. Reservoir inflow for entire time period (from early transient to late pseudo-steady state) is handled in the coupling model by integrating the instantaneous point source/sink solution over both time and space. Pressure drop along any lateral in the well system includes those caused by wall friction, gravity, and acceleration due to wall inflow or outflow. Effects of wall mass transfer on wall friction and kinetic energy change are taken into account.

A computer package has been developed and used to perform a series of sensitivity studies which lead to several important and interesting observations. The coupling model may be applied to determine well productivity, well index, wellbore pressure profile, wellbore inflow or outflow distribution for any time in the well's production/injection life.

P. 79
Preconditioned Newton Methods for Fully Coupled Reservoir and Surface Facility Models
Authors: Byer Thomas J. , Edwards Michael G. , Aziz Khalid
Published: December 2007

The 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 the development of methods that can minimize the impact of the facility model on the global solution procedure. A local grid refinement preconditioner is developed to accelerate convergence of the full flow field implicit simulation.

P. 181
Modeling the Diffusion Flux Between Matrix and Fissure in a Fissured Reservoir
Authors: Lenormand R. , Le Romancer J.F. , Le Gallo Y. , Bourbiaux B.
Published: December 2007

Numerical simulation of recovery in fractured reservoirs by simulators requires determination of transfer parameters between fracture and matrix. These large-scale transfer parameters accounts for capillary, diffusive or gravity effects and can be derived by up-scaling the local physical mechanisms. The transfer driven by capillary or gravity forces is easy to model, but there is no simple model for diffusion. Our study was aimed to calculate the transfer of a component by diffusion as a function of fracture geometry, fluid velocity in the fracture, and fluid compositions in fracture and matrix. The diffusion flux is calculated assuming a uniform fluid saturation at the interface between matrix and fracture and a laminar flow in the fracture. The coupled flow and concentration equations are solved along the width of the fracture and then integrated over its length. The resulting diffusion flux is given by a simple analytical formula. Calculations were then compared to experiments performed at reservoir conditions with pure methane injected in the fracture and binary mixtures in the matrix (Cl, C5). The results were in very good agreement, without any adjustable parameters. Finally, it is shown how the calculations can be implemented in a reservoir simulator. The fracture is considered as a porous block but then cannot directly account for the diffusion flux as a boundary condition. The only way to model the diffusion transfer is to calculate an effective diffusion coefficient which accounts for the diffusion transfer but also the grid discretization. A good agreement is obtained without any adjustable parameters between numerical simulations and experiments.

P. 259
Determination of Residual Oil Saturation Using Enhanced Diffusion
Authors: Akkurt Ridvan , Marschall Dave , Eyvazzadeh Ramsin Y. , Gardner John S. , Mardon Duncan , Dunn K.J.
Published: December 2007

The potential use of NMR as a direct indicator of hydrocarbon saturation via techniques such as the Differential Spectrum Method (DSM) has generated significant interest in the petrophysical community in recent years. Although originally developed for applications involving natural gas, the DSM has also been used successfully in light hydrocarbon environments. However, success has been limited to the low end of the viscosity spectrum because of the T1 separation requirements between the brine and hydrocarbon phases.

The T1 separation requirement in higher viscosity applications can be eliminated by using the Enhanced Diffusion Method (EDM), where diffusion is turned into the dominant relaxation mode for the wetting brine phase. Given that brine is more diffusive than the hydrocarbons, the longest apparent T2 from the brine phase can be made short enough to cause separation between the two phases in T2 space, thereby eliminating the need for T1 separation. Wait time manipulation can then be used to quantity hydrocarbon volumes when the two phases are separated in T2 domain.

This paper focuses on the determination of residual oil saturation using EDM, while also providing guidelines for job screening and acquisition parameter selection. Several case histories provided are used to illustrate basic concepts and different methodologies available.

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Holbrook Anticline, Arizona: An Exposed Analog for Fractured Reservoirs Over Salt- Dissolution Fronts
Authors: Neal James T. , Lorenz John C.
Published: December 2007

Fractured late Paleozoic and Mesozoic strata at the southern edge of the Holbrook basin in east-central Arizona overlie an active salt-dissolution front. Where the evaporates have been dissolved, the overlying strata have been offset by approximately 100 m, creating a draped monocline called the Holbrook Anticline. This dissolution-front monocline extends along a northwesterly trend for more than 100 km. Strata immediately over the dissolution front have been stretched by bending during migration of the front. The regional fractures that were present in these strata have been reactivated in extension, and some of the fractures at the crest of the anticline now have "apertures 1, up to several meters wide. Large wedges of rock between fractures are locally displaced downward as much as 15 ml forming small grabens. Many of these grabens were enlarged to form sink holes hundreds of meters across that are filled with talus breccia that formed from collapse of the overlying strata. Buckling of the surficial strata is also present in localized compressional zones associated with bending at the toe of the anticline and elsewhere. This suite of features comprises a model that can help to refine interpretations of the reservoir characteristics of fractured oil and gas fields associated with similar, deeper, dissolution fronts, such as the Silo field in Southeastern Wyoming.

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Risk Analysis: Lessons Learned
Authors: Alexander J. A. , Lohr J. R.
Published: December 2007

During the past 30 years the petroleum industry has generated significant information on risk analysis methods for exploration and development projects. However, some people continue to ask the question "Is it worth the effort?" or comment "It has not worked for me."

The authors have learned many lessons during the past few years that resulted in an improved risk analysis process. The following recommendations will ensure a successful risk analysis process. Written guidelines are necessary to avoid misapplication of established methods. These guidelines should be well documented, communicated to everyone involved in the process and regularly updated.Oversight of the risk evaluation process is necessary to maintain consistency, eliminate bias, and check for misinterpretations that occur through lack of understanding.Risk analysis training for both technical professionals and management is essential.Evaluation software should be accessible, standardized, easy to use and adaptable to changing technology and needs.An understanding of dependency between variables is vital.Risk methods should be adaptive to allow integration of new techniques, such as seismic direct hydrocarbon indicators (DHCIs), into the process.Results from risked projects should be understood and tracked closely over time to facilitate adjustments and enhancements to the methods.
Understanding Fracture Performance by Integrating Well Testing & Fracture Modeling
Authors: Cipolla C.L. , Mayerhofer M.
Published: December 2007

This paper presents case histories and field data that details the application of well test data to "calibrate" fracture models, understand fracture performance, and optimize treatment designs. The paper includes field results from gas reservoirs in the Rocky Mountains, West Texas and East Texas. In addition, the case histories illustrate the application of postfracture pressure buildup data to identify reasons for fracture treatment problems and confirm treatment success. The paper also includes a novel data set that illustrates fracture performance from a liquid CO2 stimulation (no sand, no water) in West Texas. The case histories illustrate the importance of integrating well test data with fracture treatment optimization, showing how this process can improve our ability to reliably make multi-million dollar decisions concerning proppant selection and fracture treatment size.

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Well Performance and Completion Effectiveness in the Baldy Butte Field, Washakie Basin, Wyoming
Authors: Cramer Dave , Stallings Darrick
Published: December 2007

The Baldy Butte field is located in the East Washaltie subbasin of the Greater Green River Basin and is several miles east of the prolific Echo Springs/ Standard Draw Almond bar sand trend. Wells are completed in the upper 300 to 400 ft of the Almond formation (Upper Mesaverde), at a true-vertical depth of around 8000 ft. Production is wet-gas (10–14 bbl of condensate mmscf gas) and occurs from naturally fractured low-stand deltaic, marine and fluvial point-bar sand deposits. These sands are over-pressured (0.57 psi/ft gradient), possess an average permeability of 0.04 md, and exhibit variable continuity within the field. Most of the field development has occurred over the last 2 1/2 years, and has involved contrasting well-completion methods, each specific to the three companies that operate wells in the field. This paper documents an analysis of 29 recent, contiguous completions in the Baldy Butte field, comparing the effectiveness of the three contrasting completion stimulation methods. The evaluation was based primarily on use of the reciprocal productivity index (RPI) graphical production-analysis method. Using RPJ, daily production and wellhead pressure data for each well was used to dissect well performance, obtaining information on reservoir flow capacity, stimulation effectiveness, reservoir flow geometry, drained area/volume, and produced liquid management. Distinct differences in reservoir quality and effectiveness among the contrasting completion methods were observed.

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Prudhoe Bay Field: Facility Consolidations Pave the Way for an Economic Future
Authors: Eager K.D. , Briscoe M.D. , Bolduc R.A.
Published: December 2007

The Prudhoe Bay Field on Alaska's North Slope has produced for twenty-one years. Prudhoe's gas and water production rates are at historic highs, but the oil production rate has declined to less than one-half of the peak rate achieved in the 1980's. As a result, significant excess oil treating capacity exists, with water and gas handling capacity constraining the current oil production rate. The owners of the Prudhoe Bay Unit ("PBU") developed a major facility consolidation plan in 1997 designed to rationalize this excess oil treating capacity while preserving existing gas and water handling capacity. The reconfigured facilities are expected to provide sufficient capacity at a lower cost to accommodate projected oil, water and gas production rates over the remaining life of the Prudhoe Bay Field.

This paper describes the Prudhoe Bay Surface Facility Optimization Project, from conceptual engineering initiatives in 1996. through preliminary engineering, economic justification, attainment of support from operations personnel and approval by the working interest owners of the Prudhoe Bay Field. Technical challenges and the challenges of projecting benefits associated with the consolidations were resolved through networking and technical discussions throughout the BPX, ARCO and Exxon world-wide organizations. The ultimate approval of the plan by the PBU Working Interest Owners is a clear example of teamwork and information sharing on a global scale.

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