bluuebunny/crossref_metadata_2025 huggingface dataset:
A Study of Water Coning in the Oil Creek Reservoir, North Antioch Field, Oklahoma
Authors: Cutler J.M. , Rees W.A.
Published: December 2007

In reservoirs with bottom-water drives, water coning has historically been a producing problem. Prior to the use of high-speed problem. Prior to the use of high-speed computers, the coning problem practically defied solution. This paper discusses a study of water coning in the Oil Creek reservoir of the North Antioch field, which was made utilizing an r-z, two-phase compressible coning model. The model matches water-cut history and predicts future performance. The study points up the importance performance. The study points up the importance of variation in vertical permeability on the coning phenomenon. More particularly, it shows the effects of a continuous 4-ft zone of low permeability which occurs in the reservoir. permeability which occurs in the reservoir. Coning characteristics of wells in which the original oil-water contact was located above the zone are compared with those in which the original contact was below the zone. The study indicated that the reservoir could safely be produced at rates that would greatly increase produced at rates that would greatly increase the present worth value of the reserves without materially affecting the ultimate recovery.

Introduction

The North Antioch field is located in the northwest part of Garvin County, Okla. The field was discovered in May, 1965, with the drilling of Coastal States' J. R. Winchester No. 1. As the field developed, it became obvious that the oil reserves in the Oil Creek reservoir were of substantial proportions. Development was essentially complete by Oct., 1966. Because of a rather unusual combination of reservoir and fluid characteristics and the obvious possibilities for increasing recoverable reserves, possibilities for increasing recoverable reserves, reducing costs and increasing present worth value through proper operation, the decision was made to utilize some advanced forms of reservoir modeling to predict the results of various possible methods of operation of the field. This paper presents the results obtained from modeling and recommendations for future operations in the field.

RESERVOIR CHARACTERISTICS

The Oil Creek reservoir of the North Antioch field is made up of approximately 108 ft of fairly uniform and clean Ordovician sandstone found at a depth of approximately 6,500 ft subsea or 7,500 ft subsurface. Through coring and analysis of logs, it was determined that the average porosity and permeability of the sand are 17.32 percent and 350 md, respectively. Fig. 1 is a portion of a typical electric log of the Oil Creek sand in the field. Table 1 shows the results of core analysis on two cores taken from the Oil Creek reservoir. The most striking of the characteristics of the sand is its uniformity as indicated by the SP portion of the log and the core analysis. There is one noticeable exception to the uniformity and that is the portion marked "barrier" on Fig. 1. portion marked "barrier" on Fig. 1.
S.S. Manhattan's Northwest Passage Voyage
Authors: Fuson T.J.
Published: December 2007

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.

This paper begins with the discovery and prior knowledge of oil on the North Slope of prior knowledge of oil on the North Slope of Alaska. A discussion of the hostile environment and the problems it generates is included.

The need for transporting the oil to the U.S. East Coast market is emphasized. A number of alternative transportation routes are mentioned before arriving at the three basic alternatives:Pipeline across Alaska — tankers to the Puget Sound area — and then by U.S. Transcontinental pipeline to the East Coast,Pipeline from the North Slope directly across Canada to the Eastern part of the U.S., andIcebreaking tankers eastward through the Northwest Passage.

The first two of the above are discussed briefly prior to going into the heart of the paper the full scale icebreaking tanker paper the full scale icebreaking tanker test by the S.S. MANHATTAN.

The discussion of the MANHATTAN begins with a brief history of the research which went into the decision to try a full scale test. The objectives of the test and the ship modifications are explained. Emphasis is on the collection of scientific test data to facilitate the design and to determine the economic feasibility of icebreaking tankers.

The presentation is concluded with a 12-minute film taken in the Northwest Passage.

TEXT

I'm very happy to be here today to discuss with you the voyage of the S.S. MANHATTAN through the Northwest Passage and why we did it.

The "why" of it all, of course, is the discovery of oil on the North Slope of Alaska. Conservative estimates indicate there are five to ten billion barrels of oil there potentially the biggest discovery on the North American continent. Like so many other oil discoveries, it lies in a region where it is expensive, inconvenient, and difficult to operate.
The Use of Hot Gas Injection for the Recovery of Sulfur from Thin Deposits
Authors: Barnes A.L.
Published: December 2007

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.

An analysis of the use of hot inert gas for the exploitation of thin sulfur deposits was made. This analysis included theoretical heat transfer and economic investigations. The heat transfer study involved the numerical solution of equations written in cylindrical coordinates describing convection-conduction heat transfer in the zone of gas flow and conduction heat transfer in the bounding media. Of particular interest in this work was the volume of rock swept by the 250 degrees F and 350 degrees F isotherms. This is because sulfur becomes liquid at 250 degrees F but loses its mobility again at 350 degrees F.

Results showed there is probably sufficient time for sulfur movement before arrival of the 350 degrees F isotherm. The volume of rock traversed by the 250 degrees F isotherm was found to be almost porportional to the heat-injection rate. It was porportional to the heat-injection rate. It was found that injection temperatures would have to be in the 1000 to 1500 degrees F range for economic heat transfer by gas.

An economic study indicates that a hot gas drive process for sulfur production could be economical providing that a recovery efficiency greater than 50 percent could be achieved in a bed containing 25 percent sulfur. Pilot testing would be required to develop appropriate production techniques. A combination inert production techniques. A combination inert gas-water-steam process might prove superior to straight gas.

Introduction

The Frasch process has been used since the turn of the century for the insitu recovery of elementary sulfur. Favorable economics for the Frasch process depend on shallow thick deposits because it involves water injection and water and sulfur production through the same well. Therefore, the exploited zone for each well is of limited areal extent. The Frasch process also needs large quantities of water requiring a minimum amount of chemical treatment. The process, therefore, cannot be used economically to exploit many relatively thin deposits (less than 100 feet thick) especially in areas where large quantities of water are not available or require prohibitive water treatment. prohibitive water treatment. No other methods have been developed to economically exploit thin sulfur zones where operating costs are high because of the water costs. At least two processes or combinations thereof might be considered to recover elementary sulfur from thin beds. These are the injection of either (1) hot inert gas or (2) steam into certain wells and production of either inert gas and sulfur or water and sulfur from others.
A Mechanistic Model for Cuttings Transport
Authors: Clark R. K. , Bickham K. L.
Published: December 2007

A cutting generated at the bit may be transported to the surface by several different mechanisms as it moves along the wellbore. The specific mechanism depends on the wellbore angle. For high angles, where a stationary cuttings bed can form, transport is via a rolling mechanism. In intermediate angles, where a churning, moving cuttings bed can form, transport is via a lifting mechanism. At near-vertical angles, particle settling determines transport. The model described below combines fluid mechanical treatments of these mechanisms into a format for easy analysis of cuttings transport in wells of any configuration.
The Development of a Fracture-Resistant PDC Cutting Element
Authors: Cooley C. H. , Meany Nigel
Published: December 2007

The incorporation of buttressed edge geometry has led to the development of a new cutting element that has significantly improved the performance and economics of PDC drill bits. These improvements result because of enhanced cutter durability and the resulting consistency in drilling performance in applications where cutting elements are subjected to high impact loads i.e. hard formations, dynamically unstable drilling, highly interbedded formations, etc.

This paper describes the development of a durable polycrystalline diamond cutting element. The durability of the new cutter is a direct result of its unique frustoconical shape, which is engineered to reinforce the diamond table against impacts occurring parallel to the primary motion of the cutter.

Similar cutter geometry modification has previously been employed in the machine tool sector, but until now, has found no application in the petroleum drilling industry. This paper demonstrates how the same techniques have been applied to petroleum drill bits to clearly improve the life of PDC cutting elements.

Finite element analysis (FEA) and laboratory and field experimental tests are explained and results presented to illustrate the superior strength and durability of the buttressed geometry when compared to standard cutters of right circular cylinder geometry. FEA results demonstrate a 50% reduction of damaging tensile stresses in the diamond table and supporting tungsten carbide.

Laboratory test results demonstrate that buttressed cutters survive loadings that consistently destroy conventional cutters and that penetration rate is not reduced provided the cutter backrake is properly selected. Also, these experiments show the conventionally held practice of increasing backrake in harder rock drilling actually weakens the cutter unless buttressing is incorporated.

Field test results from the Denver-Julesberg Basin of Colorado, South Texas, and Colombia are presented and discussed to demonstrate how the new cutter is significantly improving bit life while maintaining the penetration rates of conventional cutters.
Issues and Techniques of Plugging and Abandonment of Oil and Gas Wells
Authors: Calvert D. G. , Smith Dwight K.
Published: December 2007

In the oil industry today there are over 600,000 producing wells, all of which will be plugged at some time in the future. Annually, approximately one-third of all oil and gas wells drilled are dry and require plugging in the abandonment process. Unless required by law, most abandonment plugs are not checked for their location and are assumed to have been properly placed. Thirty-four of the 50 states in the US have plugging rules governing the techniques for plugging and abandonment of various wells. Written over a long period of time and by varying regulatory agencies, wide variations exist in these rules. Outside the oil and gas industry, wells are drilled for industrial, disposal, and seismic purposes, freshwater production, and solution mining. All of these wells may have differing or nonexistent abandonment rules. Some states require strict procedures for abandonment of oil and gas wells, but have few or no regulations or requirements for other wells, even though these wells encounter the same freshwater formations.

This paper reviews the latest recognized techniques for plugging and abandonment, and highlights the states having the most desirable rules for plugging to preserve freshwater horizons. The paper highlights poor techniques and practices used for plugging holes, and discusses troublesome areas such as wells that are not properly plugged and abandoned. The paper presents the issues of plugging and abandonment of wells including materials, techniques, plug testing, and regulatory requirements.
A Methodological Approach for Reservoir Heterogeneity Characterization Using Artificial Neural Networks
Authors: Mohaghegh Shahab , Arefi Reza , Ameri Samuel , Hefner M. H.
Published: December 2007

For the past few years Artificial Neural Networks (ANN) have made a strong comeback to the scientific community. They are used in a variety of tasks where adaptive computing can enhance process performance. There has been a handful of papers suggesting the use of artificial neural networks in the petroleum industry1-3. These papers can be classified into two major categories. First category includes papers that recommend the use of ANN in classification of lithologies from well logs. Second category includes papers that employ ANN to pick the proper reservoir model for well testing purposes.

This paper introduces a new implementation of the neuro-computing technology in petroleum engineering. It is shown in this study that artificial neural networks possess numerous capabilities, and can be much more useful to petroleum engineers than previously thought. An implementation of artificial neural networks in characterization of reservoir heterogeneity is presented in this paper. A methodology is introduced through which different rock properties in highly heterogeneous reservoirs can be predicted with good accuracy using information deduced from geophysical well logs. Examples of such networks are presented using field data for verification.

The underlying reasons (theories) that make achievement of such complex tasks possible are discussed. The notion that artificial intelligence and neural networks in particular have immense potentials in solving complex engineering and scientific problems are addressed. The innovation now lies on the creativity of the researchers to recognize and define petroleum engineering problems that can be addressed by artificial intelligence technology.
Field Performance Of New Technique For Control Of Water Production Or Injection In Oil Recovery
Authors: Koch Ronney R. , McLaughlin Homer Charles
Published: December 2007

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.

Many successful field treatments to change injection profiles in waterflood injection wells have been performed. A new treating technique, which in most cases does not require zone isolation, has been developed and utilized in a large number of the treatments presented in this paper. Results of presented in this paper. Results of treatments performed indicate that inexpensive, inorganic gel forming materials can produce satisfactory results if they are injected so that deep formation penetration is achieved.

Field results have also shown that the same inorganic gel forming materials can be applied, with slight modification of the new treating technique, to help eliminate or substantially reduce water production in primary depletion wells for a considerable primary depletion wells for a considerable length of time. Such results indicate that the materials and techniques may be applied to control water breakthrough problems in waterflood producing wells.

Gel times of the materials are flexible, providing placement times from a few minutes to providing placement times from a few minutes to several hours. Slurries of the materials can be made for use as a tail-in material where fractures and vugs exist.

Use of the materials and techniques developed in these treatments provides a low cost method for altering injectivity profiles in waterflood injection wells as well as an economical method for controlling water production in primary depletion wells. production in primary depletion wells

Introduction

Directing the injected water in waterflood injection wells so that the floodwater is distributed in the zones containing most of the remaining oil in place has long been a challenging problem in waterflood operations.

At various intervals in the life of a flood program, it may be most economical and desirable to redistribute the floodwater to enter other zones. Controlling the fluid allotment into each formation strata may pose a costly operation if a rig or expensive downhole equipment is used. Furthermore desired results may never be seen in the producing wells. Usually, the zones of highest producing wells. Usually, the zones of highest permeability accept the floodwater first. permeability accept the floodwater first. When breakthrough occurs in such cases, much oil in place is bypassed in zones of lesser permeability. permeability.
Influence of Wellbore Hydraulics on Pressure Behavior and Productivity of Horizontal Gas Wells
Authors: Sarica Cem , Ozkan Erdal , Haciislamoglu Mustafa , Raghavan Rajagopal , Brill J. P.
Published: December 2007

The objective of this study is to investigate the effect of wellbore hydraulics on the pressure behavior and productivity of horizontal gas-wells. The semi-analytical model used to investigate the effect of wellbore hydraulics, couples gas flow in the reservoir and in the wellbore by utilizing the real gas-pseudopressure function. Pressure and flux distributions along the well are investigated. Conditions under which wellbore hydraulics manifests its effect on the pressure behavior and the productivity of horizontal gas-wells are documented. It is shown that pressure losses in the horizontal section of the well are composed of friction and acceleration losses and the two constituents are interrelated. It is shown that most of the gas enters the wellbore around the heel (the producing end) of the horizontal well and therefore measures must be taken to reduce any flow-impediment around the heel of the well. Two examples are presented to show that the utility of the model developed in this study.
Development of Optimal Water Control Strategies
Authors: Chou S. I. , Bae J. H. , Friedmann Francois , Dolan J. D.
Published: December 2007

A methodology for optimizing water control treatments presented here utilizes existing injection and production data and incorporates previous treatment results into a ranking process, which can be continuously refined as additional data becomes available. Essential sequences of this methodology are explained, and the ranking and design of producer and injector gel treatments at three midcontinental fields are illustrated. Gel treatments based on this methodology performed much better than previous ones.

A key element of the methodology is to assess the degree of communication between an injector and its offset producer. For reservoirs of significant gas saturation, such as those at early stages of waterflood, the correlation coefficient between water injection and production rates over appropriate time frames provides a quantitative estimate of such communication. Results show that offset producers having a high correlation coefficient with the pattern injector generally have positive response after gel treatments, and vice versa.
Surface Producing Equipment For Deep Gas Wells In The Delaware Basin
Authors: Martin F.H.
Published: December 2007

Operators of deep gas wells in West Texas have installed a wide variety of gas producing equipment to best utilize the productivity of specific wells and to meet gas contract requirements. Several installations are discussed, and the need for the Equipment Engineer to be familiar with gas contracts is emphasized.

TEXT

The discovery and development of the very deep natural gas reserves of the Delaware Basin of West Texas led to what has been described as the largest concentration of ultra-deep drilling rigs ever assembled in simultaneous operation. Due to the success of these operations, it may now be said that the basin also contains the largest concentration of high pressure gas producing, treating, and transmission facilities ever assembled. Fig. 1 indicates the location of some of the major gas fields of the Delaware Basin in Ward, Reeves, and Pecos Counties. This paper will attempt to illustrate and describe the producing equipment and various methods of making gas available to purchasers which have been developed by the working interest owners for some of the wells in these fields.

Fig. 2 is an example of split-flow of gas downstream from jointly owned producing equipment. The well, which producing equipment. The well, which is completed in the Ellenburger at approximately 20,000 ft, was initially tested at 23 MMCF/D at a flowing tubing pressure of 6600 psi. The producing equipment consists of a 48 in. x producing equipment consists of a 48 in. × 18 ft 2,000,000 BTU/hr steam generator and a 30 in. × 10 ft 1440 psi working pressure separator. Gas is delivered pressure separator. Gas is delivered into one owner's flow line at 1200 psi where it is transported to a flow psi where it is transported to a flow control center. Gas is delivered another owner to an on-the-site purchaser at 1200 psi by means of a purchaser at 1200 psi by means of a control valve on the separator outlet and a differential controller on the on-the-site sale meter.
History Matching Using the Method of Gradients: Two Case Studies
Authors: Bissell R. C. , Sharma Yogeshwar , Killough J. E.
Published: December 2007

We have successfully history matched two reservoirs using the method of gradients. This was achieved by defining an objective function which is the sum of the squares of the differences between calculated variables, such as a shut-in bottom hole pressures, from the reservoir simulator and their measured values. The objective function is minimised using a non-linear regression algorithm. This requires the derivative, or gradient, of the calculated variables with respect to the history matching parameters. Our reservoir simulator is able to calculate these derivatives efficiently during a simulation run. Both reservoirs had previously been matched by hand. Our results compare well with the hand matches.
Mechanism Of Inhibition Of Paraffin Deposition In Crude Oil Systems
Authors: Mendell John L. , Jessen F.W.
Published: December 2007

Introduction

The accumulation of paraffin wax in petroleum reservoirs and production equipment petroleum reservoirs and production equipment remains a continuous problem and expense in the production of oil. The use of scrapers, production of oil. The use of scrapers, hot-oil treatments and solvents has eased the problem; however, with the advent of extremely problem; however, with the advent of extremely deep production, offshore drilling and ocean floor completions, the application of remedial measures becomes prohibitive economically. As a result, use of chemical additives as paraffin deposition inhibitors is becoming more prevalent. prevalent. Since no one additive has proved universally effective, the selection of an efficient additive for a specific application becomes important, and a better understanding of the mechanism of inhibition is necessary.

Patton and Chichakli showed that high molecular weight fractions from crude oil significantly affect paraffin crystal growth and retard or prevent paraffin deposition. Hanke and Birdwell also found these fractions were adsorbed preferentially to a metal surface. Other investigators attributed decreased deposition to modifying the paraffin wax crystals or changing the wetting characteristics of the pipe surface.

The purpose of this work was to develop a technique for studying the flow characteristics of crude oil at temperatures below the cloud point, examine the effect of various additives point, examine the effect of various additives on these flow characteristics, and to correlate any change in the flow characteristics with depositional tendency.

Hanke discussed thoroughly the ideas presented by several investigators concerning presented by several investigators concerning accumulation of paraffin waxes. Tronov used a micro-moving picture camera to record paraffin deposition in a flowing well and found nucleation of paraffin crystals occurred directly on the metal surface. Paraffin crystals already in suspension were usually deposited in quiescent parts of the equipment. parts of the equipment. Hunt and Jorda consider surface roughness the only factor controlling the amount and characteristics of paraffin deposits However, Jorda also found use of smooth plastic tubing of tetrafluorethylene, polyethylene and polypropylene still resulted in massive polypropylene still resulted in massive deposits. Patton found that the presence of an adsorbed crude film on a steel surface increased the surface energy of the metal and caused greater deposition.

The association of asphaltenes and paraffin wax in wax deposits has been mentioned paraffin wax in wax deposits has been mentioned by several investigators, and Preckshot found that bitumen deposits possibly were associated with an electro-depositional effect.
Horizontal Well Production Logging in Australia
Authors: Chauvel Yves , Anderson John , Aldred Rick , de Pledge Laurie
Published: December 2007

In 1993, Australia saw a surge in horizontal well drilling and completion. This surge was motivated by two main factors: the desire to produce oil from fewer wells per field at substantially higher production rates per well, and the necessity of draining the reservoirs with horizontal wells as dictated by local conditions of formation geometry and petrophysical characteristics.

One of the most efficient ways of evaluating the productivity of a horizontal drain is to run production logs in the recently completed well. The technique used is called CTL* Coiled Tubing Logging, which was first implemented in 1988 and has become routine since.

Applications of production logging in horizontal wells include: –initial completion evaluation,–in-situ measurement of the productivity index,–flow profile determination,–multiphase flow regime characterization,–determination of unwanted water and gas entries,–dynamic reservoir characterization by pressure transient testing.

Through-tubing formation evaluation tools can also be run together with the production logs to complement openhole evaluation.

More than ten wells have been successfully logged in approximately one year, in different oil and gas provinces of Australia and in a variety of completion configurations. The paper describes the data acquisition programs, the downhole sensors which have been used and their application to horizontal flows. The data interpretation methodology is presented, and a number of interpreted examples are shown.

The paper concludes with the relevance of production logging to the optimization of production engineering, and reservoir drainage by horizontal wells.
Hydraulic Fracturing Experiments in the Great Northern Coal Seam
Authors: Jeffrey R. G. , Weber C. R. , Vlahovic William , Enever J. R.
Published: December 2007

Two field-scale hydraulic fracturing experiments were performed in vertical boreholes on the lease of Munmorah Colliery located south of Newcastle, NSW. The treatments fractured the 3- metre thick, 220-metre deep Great Northern coal seam and were designed to provide a direct comparison between a borate-crosslinked gel and a water treatment. The fracture geometries were mapped during mining of the coal seam.

Geologic mapping disclosed a well-defined coal face cleat and systematic full-seam joints perpen-dicular to bedding and trending NW. The vertical hydraulic fractures extended along the joint and face cleat direction. Evidence that an early slurry stage of fine mesh proppant acted to block off one of two competing parallel fractures was found at one of the mineback sites.
Oilwell Batch Inhibition and Material Optimisation
Authors: Russ P. R.
Published: December 2007

Weighted-batch inhibition is a technique used in Bass Strait oil wells to provide protection against corrosion. A new radiotracer Selenium-75 was attached to the inhibitor enabling the fall rates in gas, oil and water phases to be calculated. The radiotracer technique clearly showed the inability of the inhibitor to fall through the water-phase of a shut-in well and will provide a means of field testing new and better inhibitor formulations. The wear rates of the inhibitor were also calculated using the radiotracer. Laboratory tests were conducted to correlate the inhibitor concentration with minimum inhibitor film thickness required to give the maximum corrosion protection. A concentration of 5000 ppm gave a film thickness of 4.6 x 10-3 mm which corresponded to the optimum protection for the particular inhibitor and corrosion test used.

The lower sections of a number of wells were found to be protected not by inhibition but by tubing metallurgy. Caliper evidence is presented that clearly shows that metallurgy plays a significant role in controlling corrosion. The chemical composition and metallography of the well tubing is presented. As-rolled J55 material had superior corrosion performance than L80 material. The J55 material thermal history determines its corrosion behaviour.
Analysis of Limited-Entry Well Tests in Layered Reservoirs
Authors: Hayes M. R. , Naismith J. D. A. , Gunasekera D. L. , Fitzpatrick A. J.
Published: December 2007

Vertical permeability, often a key parameter in reservoir engineering, can be calculated from the analysis of a limited entry pressure transient. Analytical solutions for limited entry welltests, where a fraction of the reservoir interval is perforated, have been available in the literature for some time. This paper considers the evaluation of limited entry welltests in heterogeneous layered formations. A number of field examples have been analysed using both conventional analytical techniques and a new general purpose numerical welltest analysis application. The examples show that in layered formations vertical permeability can be significantly under estimated by conventional analytical analysis.
Three-Phase Flow in Field-Scale Simulations of Gas and WAG Injections
Authors: Guzman R. E. , Domenico Giordano , Fayers F. J. , Aziz Khalid , Godi Antonella
Published: December 2007

Three-phase flow is present in many oil recovery processes of interest to the oil industry. It occurs in processes such as primary production below bubble point pressure in reservoirs with water drive, in gas or water alternating gas (WAG) injection into waterflooded reservoirs, in thermal oil recovery, and in surfactant flooding. Despite its common occurrence, our ability to reliably model three-phase flow using numerical simulation is questionable. This paper shows the importance of three-phase flow at typical oil field conditions. It also shows the uncertainties in the predictions of oil recovery due to the three-phase relative permeability model.

Numerical simulations of immiscible gas and WAG injection into a waterflooded one eighth of a five-spot were performed to determine the importance of the three-phase flow at conditions that are of interest to the oil industry. Consistent oil-water imbibition and oil-gas drainage relative permeability and capillary pressure were derived for this purpose, including a new form for imbibition capillary pressure.

Dimensionless scaling groups for three-dimensional three-phase flow in porous media were developed. The scaling groups were used to design simulations at various conditions of gravity, viscous and capillary force interactions. In addition, several simulations were made to determine the uncertainty of the results due to the model for three-phase relative permeabilities.

The results of this study show that there is a significant uncertainty associated with the selection of the three-phase relative permeability model for field scale simulations of gas and WAG injections. This uncertainty is translated into doubtful simulation results in terms of distribution of the fluids inside large volumes of the reservoir, total oil recovery, and fluids production rates. It is shown that additional oil recovery due to gas injection after a waterflood can be different by a factor of two depending on the model for three-phase relative permeability. It is also shown that the producing gas oil ratio (GOR) varies considerably depending on the model for three-phase relative permeability, while maintaining the same two-phase relative permeabilities. Accurate predictions of oil recovery in processes that exhibit three-phase flow need more rigorous models for three-phase relative permeability.

Large three-phase flow regions were present for most of the conditions simulated. The size of the three-phase flow regions ranged from 20% to 80% of the volume of the reservoir. The size of the three-phase flow region was a strong function of the kro model used. Thus, an argument asserting that only a small part of the reservoir is affected by the uncertainties in the three-phase relative permeability model is not supported by these results.
Use of High-Angle, Acid-Fractured Wells on the Machar Field Development
Authors: Gilchrist J. M. , Stephen A. D. , Lietard O. M. N.
Published: December 2007

The Machar field, located in UKCS Block 23/26a, contains an estimated STOMP of 290 MMSTB, predominately found in high porosity, low permeability chalk formations. Draped over the flanks of a salt diapir, the chalk formation exhibits a variable degree of natural fracturing depending upon its position on the structure.

Following initial appraisal of the structure, it was clear that to optimise field development, a well designed to intersect with as many natural fractures as possible would offer high well rates while minimising drawdown to aid in reservoir management and recovery optimisation.

This paper describes the use of a stratigraphically high angle well which was drilled to fulfill these requirements. Following discussion of the well’s completion and stimulation design, the field implementation and evaluation will then be reviewed.

The successful high rate damage removal / acid fracturing treatment has led to this appraisal/development well being placed on long term production as part of a pilot scale development of the reservoir.
An Improved Model for Laboratory Measurement of Matrix to Fracture Transfer Function Parameters in Immiscible Displacement
Authors: Gupta Anuj , Civan Faruk
Published: December 2007

The recovery model proposed by Civan4,5 was extended to account for additional mechanism of mass transfer from matrix to fracture. This led to triple exponential functions that offered significant improvement in the agreement between experimental and predicted oil recovery during imbibition. Inclusion of contact angle in the time scaling group resulted in significantly improved correlation amongst the imbibition recovery for samples with varying shapes and sizes, flow boundary conditions, and fluid and rock properties. The analysis presented here allows the estimation of a representative contact angle. Three distinct exponential terms were identified for experimental data analyzed. Such functions matched the cumulative oil recovery for early as well as late time.
An Integrated Experimental Methodology for a Better Prediction of Gas-Condensate Flow Behavior
Authors: Bourbiaux B. J. , Limborg S. G.
Published: December 2007

This paper demonstrates the possibilities offered by an integrated experimental methodology to measure the critical condensate saturation (Sec) and relative permeabilities (kr) of gas-condensate fluid systems.

This methodology involves various procedures such as equilibrium gas injection and two-phase (steady-state) injection. The innovative aspects of the methodology are (1) a visual onstream control of fluid PVT behavior and (2) local condensate saturation measurements using gamma-ray attenuation technique with a specific method of calibration.

Experiments have been performed under two interfacial tension (IFT) conditions with a low-permeability sandstone and methane-propane (C1C3) binary fluid system in the presence of an interstitial water saturation. Sample results are given, mainly for the low IFT condition (0.03mN/m). For this IFT, a low Sec, 4 to 9%pore volume (PV), is found in the presence of an interstitial water saturation (Swi) of 17 to 22% PV. Sec value is linked to the value of Swi. A dependence of Sec on IFT seems to have been detected but requires further investigation. Under steady-state flow conditions, fairly high relative permeabilities to gas and low relative permeabilities to condensate were found with our rock-fluid system for both IFT values investigated. Measurements of condensate distribution within the core enabled real-time control of flow conditions and explained some literature discrepancies in Sec values.

This new multi-purpose experimental methodology enables a reliable determination of IFT-indexed kr curves required to predict the productivity of gas-condensate fields subjected to pressure depletion.
Gelling Behavior of 12-Hydroxystearic Acid in Organic Fluids and Dense CO2
Authors: Gullapalli Pratap , Tsau Jyun-Syung , Heller John P.
Published: December 2007

This paper presents the gelation results of a variety of organic fluids and supercritical carbon dioxide with 12-hydroxy stearic acid (HSA). At low concentration (0.75 wt%), HSA caused thermoreversible gelation of a variety of organic fluids such as aliphatic, alicyclic, aromatic hydrocarbon liquids, chlorinated fluids, and mixture such as Soltrol-130.

As low as 0.75 wt% of HSA also gelled high pressure solutions of dense CO2 and the selected organic fluids such as alcohols and chlorinated fluids. In the absence of any cosolvent, HSA was insoluble in dense CO2 at 1800 psig and 34°C. However, with 10-15% ethanol, HSA was found to be totally soluble in CO2 at the above experimental conditions. Results indicate the mixture of HSA/ethanol or chloroform gels CO2. The ungelled mixture of HSA/cosolvent and CO2 is clear whereas it turns to translucent or opaque when it gels. Viscosity measurements were made of mixtures of HSA with ethanol in dense CO2 at 1800 psig between 21 to 34°C, using a high pressure capillary viscometer equipped with a sapphire cell for visual observations. These showed that the gelation of CO2 with HSA depends on the temperature and concentration of both HSA and cosolvents, which affect the gel temperature (Tg) and viscosity of CO2. The presence of cosolvent enhances the solubility of HSA in CO2 and increases its viscosity.
Studies on Phenol-Formaldehyde Crosslinked Polymer Gels in Bulk and in Porous Media
Authors: Albonico Paola , Bartosek Martin , Malandrino Alberto , Bryant Steven , Lockhart T. P.
Published: December 2007

The general conditions for gel formation by phenolformaldehyde polymer solutions have been examined in studies with three acrylamide polymers. Contrary to an earlier report, polymer crosslinking is found to take place over a wide interval of pH. While the gelation time is relatively insensitive to the concentrations of phenol and formaldehyde or pH, it is strongly influenced by the temperature and the nature of the polymer. These gelants display good injectivity in corefloods and slim-tube experiments at temperatures up to 140°C. On the other hand, the partitioning of phenol into crude oil is found to be a significant issue for the propagation of these gelants. The use of a phenol pre-flush of the formation is shown by numerical modeling to be a potentially viable solution for this problem.
Mechanistic Study and Modelling of Precipitation Scale Inhibitor Squeeze Processes
Authors: Malandrino Alberto , Yuan M. D. , Sorbie K. S. , Jordan M. M.
Published: December 2007

A scale inhibitor "precipitation" squeeze is one of the two main types of treatment for preventing downhole scale deposition; the other type is an adsorption squeeze. However, unlike for the adsorption squeeze process, the mechanism for inhibitor retention within the formation through precipitation/re-dissolution is not fully understood and it is this issue that is considered in this work. Here, our central objective is to consider a range of possible models of the precipitation squeeze process and to determine which of these are consistent with the available laboratory core flood and field data. Such models range from pure precipitation through to more complex models which couple the precipitation process with an adsorption process or with a "mechanical transport" phenomenon. The various models are explained in terms of the chemical processes which are observed. Results from two inhibitor precipitation core floods and one field squeeze treatment are presented along with the modelled inhibitor return curves. Based on certain model assumptions, our understanding of the process allows us to optimise the squeeze design of both inhibitor solution and operational parameters for extending the precipitation squeeze life time.
Grieve Unit - High Recovery Muddy Sand
Authors: Hurd J.D.
Published: December 2007

The Grieve Unit is in Natrona County, Wyoming, 35 miles west of Casper in the southeastern portion of the Wind River Basin of Central Wyoming. The producing oil reservoir is a stratigraphic trap in the Muddy sandstone which occurs on a monoclinal structure at a depth of 6,900 ft.

This Wyoming "Giant" has produced nearly 28 million barrels of oil since discovery in August of 1954 and presently ranks 20th in the State on a cumulative oil recovery basis. Over 50 percent of the oil-in-place has been recovered. by the various mechanisms including an original gas cap, gas injection, gravity segregation and a strong water drive.

Three submersible pumps are installed in downdip, high water cut wells in order to achieve the higher recovery from gravity segregation. A liquid hydrocarbon plant strips the liquids from the cycling gas production and the products are blended with 36 degrees API crude oil for increased gravity.

Forest Oil Corporation drilled the discovery well in this Muddy sand field and is the Unit Operator with nearly 95 percent working interest. It is estimated that there will be ten more years of crude oil production before gas cap gas blowdown time.

This paper reviews operations and the reservoir properties that have been estimated and calculated.

Introduction

Presentation of this paper is the result of renewed exploration activities of recent in the Wind River Basin in general, and in the Muddy sand of northeastern Wyoming in the past several years. However, the value of the paper, besides nostalgia for some, should be paper, besides nostalgia for some, should be limited to any permeable, steeply dipping sandstone of the Northern Rockies.

The qualifications of the author are that he was an under-graduate engineer 1,000 miles away during discovery and early life of the Grieve Unit and most of his reservoir work with Forest Oil has been on other reservoirs. Nevertheless, previous reports and records have been reviewed again and Forest personnel that were knowledgeable of the history of the Grieve were interviewed.
Network Model For The Study Of Multiphase Flow Behavior In Porous Media
Authors: Singhal A.K. , Somerton W.H.
Published: December 2007

In designing a displacement recovery process, it is desirable to have a method of predicting how the relative permeability, capillary pressure, residual oil saturation and hence the displacement efficiency will be governed by the controllable variables, i.e., viscosity ratios, interfacial tensions, contact angles and flooding rates. This paper describes a simulation procedure in which a network model for the reservoir rock is generated by the Monte-Carlo technique, using pore size distribution and structural parameters appropriate to the particular reservoir. Applying existing hydrodynamic and thermodynamic knowledge about two-phase flow in pore spaces the displacement mechanism in the porous medium is simulated. pore spaces the displacement mechanism in the porous medium is simulated. Progress of the flood is followed pore-space by pore-space over the entire Progress of the flood is followed pore-space by pore-space over the entire network model and data on the effluents from the model boundary provide information on the performance. The model has been used to study displacement behavior in unconsolidated sand packs. The model results simulate the relative permeability behavior of porous media quite satisfactorily but rather permeability behavior of porous media quite satisfactorily but rather semi-quantitatively.
Core-log Data Integration for Improved Formation Evaluation in the Dulang Field, Offshore Peninsular Malaysia
Authors: Bin Tajul Amar Zarool Hassan , Egbogah Emmanuel O. , Bin Nurdin Abdul Rahim
Published: December 2007

One of the most challenging tasks of a log analyst is to understand log responses. In order to achieve this it is essential to establish an accurate Bulk Volume Model for the reservoir. This includes mineralogy, porosity and saturations. Unfortunately, in the case of Dulang field, log data alone cannot be used to derive accurately the Bulk Volume Model due to insufficient log data and the presence of special minerals. These minerals which affect log responses significantly are Potassium-Feldspar, Siderite and Fe-Dolomite. Dulang field is a complex shaly-sand reservoir situated 130 kilometres offshore Peninsula Malaysia.

This paper illustrates how results of core analysis have helped us understand log responses in the Dulang field. A special core recovery program was carried Out in three wells, namely, Dulang-A17, B20 and B21, which penetrated all the major reservoirs that contributed the bulk volume of STOIIP in the Dulang field. A low toxicity oil-based mud was used in well Dulang-B21 to establish accurately the connate water saturation for quantitative calibration of log derived parameters. A bland water-based mud was used in the other two wells to preserve the rock wettability. The results of the core analysis enabled us to better refine our petrophysical model of the reservoir which led to a more accurate computation of reserves.

Components of core analysis used in this study are Fourier Transform Infra-Red spectroscopy, Core Layering and conventional core measured petrophysical parameters (porosity, permeability, grain density and saturations).