bluuebunny/crossref_metadata_2025 huggingface dataset:
Fracture Treatment Design To Overcome Severe Near-Wellbore Damage, Mereenie Field, Australia
Authors: Papinczak Anthony , Miller W. K.
Published: December 2007

The Mereenie field, located about 185 miles west of Alice Springs in the Northern Territory of Australia, consists of a large gas cap surrounded by a narrow oil rim. The oil rim has been the predominant target, with the majority of oil produced from the Pacoota P3-120/130 sandstone reservoir. At approximately 4,500 to 5,000 ft, the reservoir exhibits permeabilities of 5 to 100 md. Pressure-transient analysis and production characteristics of early wells indicated increasingly high levels of near-wellbore damage, discovered later to be associated with fines migration and an extensive illite clay network. In an attempt to overcome this impairment, seven hydraulic fracturing treatments were performed between 1983 and 1987; however, postfracture results were disappointing. Extensive well testing, laboratory work, and reservoir/fracture modeling identified major problem areas associated with both the reservoir and the fracture treatments. During 1991–92, seven additional treatments were performed to achieve a tip screenout (TSO) to form a short, highly conductive flow path to bypass the damage. These resulted in a significant increase in production, an upgrade in the field's recoverable reserves, and additional development drilling.
Prediction of Effective Acid Penetration and Acid Volume for Matrix Acidizing Treatments in Naturally Fractured Carbonates
Authors: Xiong Hongjie
Published: December 2007

This paper discusses a new method and a corresponding computer model developed to investigate matrix acidizing in naturally fractured carbonates. With this method, the effective acid penetration distance and acid volume needed for acid treatments in naturally fractured carbonates can be predicted. The new model simulates acid flowing in the natural fracture network and the acid/rock reaction. During the simulation, the model considers the influence of formation temperature, reaction heat, and common ion effect on acid penetration. A set of graphs showing the relationship between acid penetration and the acid volume needed in different formations was developed from numerical simulation results. From these plots, the acid volume that should be used to remove the formation damage can be determined easily when the formation temperature and the damage radius are known or can be estimated.
Application of a 3D Hydraulic-Fracturing Simulator for Design of Acid-Fracturing Treatments
Authors: Morgenthaler L. N.
Published: December 2007

Field experience during 1989-90 shows that application of a 3D hydraulic-fracturing simulator increases success of acid-fracturing well treatments. Fracture extension can be limited to the oil-bearing pay, maximum lateral extension can be realized within the height constraint, and acid/rock contact time can be increased by a factor of between 3 and 30. Oil-production response can be improved over other stimulation designs while water-production response can be limited. These methods have been applied in mature waterfloods of the Permian Basin and Cedar Creek anticline.
Rate/Depth Tubing-Performance Curves
Authors: Winkler H. W. , Eads P. T.
Published: December 2007

An accurate method for predicting the range of multiphase flow rates through different tubing sizes is an important production tool. Properly sized tubing will prolong the flowing life of a well and minimize the injection-gas requirements for gas-lift installations. A tubing string can be oversized or undersized. This paper presents a method for relating the four basic parameters for different tubing sizes: daily liquid production rate, tubing length or depth of gas injection, flowing production pressure at depth or surface operating injection-gas pressure, and the gas/liquid ratio (GLR). This information is displayed as rate/depth tubing-performance curves, which are based on the Shell Ros-Gray multiphase flow program. These curves allow proper tubing-size selection for a predicted range of daily production rates.
Differentiating Formation Compressibility and Water-Influx Effects in Overpressured Gas Reservoirs
Authors: Poston S. W. , Chen H. Y. , Akhtar M. J.
Published: December 2007

The material-balance equation for overpressured gas reservoirs was rearranged so that the outcome variables are original gas in place (OGIP), formation compressibility, and water-influx values. A set of typical curves is presented to allow comparison of field cases and theoretical situations.
Controlling Asphaltene Deposition in Oil Wells
Authors: Thomas D. C. , Becker H. L. , Del Real Soria R. A.
Published: December 2007

The deposition of asphaltenes in oil producing formations and production systems has caused problems for years. Selection of chemical control agents in the past has been limited to bulk dissolution studies on samples retrieved from production systems. Until recently, the accepted way to treat these problems has been through the use of xylene, toluene or other aromatic solvents. This method requires the use of large amounts of these solvents, as well as a high frequency of treatment. This paper describes the results of field testing and application of asphaltene control chemicals, and the use of laboratory tests to select asphaltene deposition removal and prevention chemicals.

Preliminary dispersant and solvency tests are conducted by an asphaltene dispersant test in hexane. Chemicals which provide promising results in dissolving and dispersing asphaltenes in the non-solvent medium of hexane are selected as candidates for field application, or for additional testing in a core flow deposition removal test.

The core flow test apparatus provides a method to introduce asphaltene fouling into a core and study its removal by the use of chemical agents. Using core samples and asphaltenes from the production resource under consideration allows the selection of the best removal chemical.
Borehole-Stability Model To Couple the Mechanics and Chemistry of Drilling-Fluid/Shale Interactions
Authors: Mody F.K. , Hale A.H.
Published: December 2007

A borehole-stability model that uniquely couples the mechanical and chemical aspects of drilling-fluid/shale interactions was developed. The model allows the user to determine the optimum drilling parameters (e.g., mud weight and salt concentration) to alleviate borehole-stability-related problems with oil- or water-based drilling-fluid systems. Chemically induced stress alteration based on the thermodynamics of differences in water molar free energies of the drilling fluid and shale is combined with mechanically induced stress. These two potentials are coupled by use of the framework of poroelasticity theory to formulate the physiochemical basis of this borehole-stability model.

Introduction

Shales make up more than 75% of drilled formations and cause more than 90% of wellbore-instability problems. Drilling shale can result in a variety of problems, ranging from washout to complete hole collapse. More typical drilling problems in shales are bit balling, sloughing, or creep. The problems are severe and have been estimated conservatively to be a $500 million/yr problem for the industry. These engineering problems are closely connected with the "bulk properties" of the shale, such as strength and deformation as a function of depositional environment, porosity, water content, clay content, composition, and compaction rates. The drilling-fluid bulk properties (such as the chemical makeup and concentration of the continuous phase of the mud; the composition and type of an internal phase, if present; the type of additives associated with the continuous phase; and the maintenance of the system) also are of utmost engineering importance. Other factors - in-situ stresses, pore pressure, temperature, time in open hole, depth and length of openhole interval, surrounding geological environment (salt stringers, dome, etc.) - also directly affect drilling and completion operations and must be integrated into any model and new mud system development. These variables are interconnected and influence the overall behavior of shales during drilling.
Development of Roller Cone Bits With Active PDC Shear Cutting Elements Improves Gage-Holding Ability
Authors: Scott D. E.
Published: December 2007

A patented roller-cone bit that combines the conventional drilling mechanics of a roller-cone bit with the shearing action of polycrystalline diamond (PDC) cutting elements to trim gage has been developed.1 This paper reviews design features of the bits, laboratory tests demonstrating the shearing action, and presents case studies of bits with the shear-cutting PDC-gage elements.
Determination of Acoustic Velocities for Natural Gas
Authors: Thomas L.K. , Hankinson R.W. , Phillips K.A.
Published: December 2007

Acoustic velocities for natural gas are calculated as a function of temperature, pressure, and gas gravity. The method is based on a generalized equation of state for natural gas that may also be used to calculate a number of thermodynamic properties such as specific internal energy and isentropic expansion.

Introduction

Some uses of acoustic velocities for natural gas are to determine liquid levels in gas wells and to locate hydrate freezes, lost ‘pigs’, or other obstructions in gas pipelines. These distances can be calculated from well defined acoustic records (Fig. 1a) by associating the number of pipe sections with their corresponding lengths. If, however, an uninterpretable acoustic record (Fig. 1b) is obtained, or if the lengths of the pipe sections of a given flow string are unknown, pipe sections of a given flow string are unknown, distance between the shot deflection and the reflecting surface can be obtained by integrating the relationship between velocity distance and time

(1)

The utility of this technique depends upon one's ability to calculate acoustic velocities and to measure system variables such as gas gravity or composition, temperature, temperature gradient and pressure. In the past, acoustic velocities have been calculated from an approximate relationship involving atmospheric heat capacity ratios rather than ratios that are a function of pressure. As has been pointed out, this approximate relationship provides a good working equation for calculating acoustic velocities at low pressure ranges but should not be used at higher pressures. The purpose of this work is to present a method for rigorously calculating acoustic velocities for natural gas over a broad range of temperatures, pressures and gas gravities.

Calculation of Acoustic Velocity

Starting from the equation for the speed of sound in a compressible fluid

(2)

it is possible to derive the following equation for a real gas (see Appendix).

(3)

Eq. 3 can also be expressed in terms of the isentropic expansion coefficient, n, since

(4)

Making this substitution yields

(5)

To compute the velocity of sound in a real gas from either Eq. 3 or Eq. 5, it is necessary to know the PVT behavior of the gas and the variation of the beat capacity ratio with temperature and pressure. To accomplish this, an equation of state for natural gas was developed.

JPT

P. 889
Multidisciplinary Reservoir Characterization and Simulation Study of the Weyburn Unit
Authors: Elsayed S.A. , Baker Richard , Churcher P.L. , Edmunds A.C.
Published: December 2007

Reservoir characterization is important to EOR and numerical simulation studies, especially for complex naturally fractured reservoirs with low-permeability matrix rock. Solvent movement and volumetric sweep are controlled by fracture distribution and connectivity and by matrix permeability variation. All these factors were considered in our reservoir characterization and simulation study.

The reservoir characterization was so effective that, in a 63-well simulation study, 70% of the wells were history matched on the first simulation runs without modification to the original geologic/petrophysical data. This can be attributed to the team approach of using geological, reservoir engineering, and petrophysical input.

Introduction

The Weyburn Unit, in the southeastern corner of Saskatchewan, has produced medium-gravity crude oil from the fractured, low-permeability Midale beds of the Mississippian Charles formation since its discovery in 1954. Even though the Weyburn Unit has been on waterflood for more than 26 years, a significant target for EOR, horizontal wells, and waterflood optimization remains.

The Weyburn field is located ~130 km southeast of Regina, Sask. (Fig. 1). The productive portion of the field covers ~180 km2. The field currently has 627 producing wells and 162 water injection wells on ~24-ha spacing.

The Midale beds of the Weyburn field were produced by primary depletion from discovery until 1964, when an inverted nine spot waterflood scheme was implemented. Since 1985, both horizontal and vertical infill drilling programs have been undertaken to optimize waterflood performance.

The Midale beds of the Mississippian Charles formation were deposited on a shallow carbonate shelf in the Williston basin. The reservoir is informally subdivided into the upper Marly and the lower Vuggy zones (Fig. 2).

The Marly is a chalky intertidal dolostone with occasional limy or limestone interbeds. Porosity in the dolostones ranges from 16% to 38%, with an average of about 26%. Matrix permeability within this reservoir horizon ranges from 1 to >100 md, with an average of <10 md.
Comparison Study of Hydraulic Fracturing Models—Test Case: GRI Staged Field Experiment No. 3
Authors: Warpinski N. R. , Moschovidis Z. A. , Parker C. D. , Abou-Sayed I. S.
Published: December 2007

This study is a comparison of hydraulic fracture models run using test data from the GRI Staged Field Experiment No. 3. Models compared include 2D, pseudo-3D, and 3D codes, run on up to eight different cases. Documented in this comparison are the differences in length, height, width, pressure, and efficiency. The purpose of this study is to provide the completions engineer with a practical comparison of the available models so that rational decisions can be made as to which model is optimal for a given application.
An Integrated Approach to Evaluation of Horizontal Well Prospects in the Niobrara Shale
Authors: Stright D. H. , Robertson R. D.
Published: December 2007

Integrated use of surface and subsurface geologic data, structural deformation analysis from second-derivative maps, and dimensionless type curves in identifying potential horizontal well locations in the fractured Niobrara Shale of northwest Colorado is described. The analysis included construction of detailed structure maps from surface geology with tie-ins to seismic surveys and well control and of second-derivative maps that were overlaid on production data to determine the minimum radius of curvature required for commercial production. Reservoir properties were calculated for known fields from type-curve matching with type curves for dual-porosity, anisotropic reservoirs with stress-sensitive permeability. The curves were constructed for vertical and horizontal wells by use of reservoir-simulation models. Spacing and economics of drilling horizontal Niobrara wells in northwest Colorado were evaluated. The analysis suggests that recoverable oil from the fractured Niobrara in northwest Colorado averages 1,392 bbl oil/acre on the basis of a productive fracture area identified by second derivatives of the structural surface with values > 1 × 10−4.5ft−1. It is also indicated that horizontal wellspacing in the fractured Niobrara should be > 640 acres. In some instances, it may be more economical to develop the fractured Niobrara with vertical rather than horizontal wells.
High-Temperature Reprocessing of Petroleum Oily Sludges
Authors: Hahn W. J.
Published: December 2007

Crude oil tank bottoms and other petroleum oily sludges and emulsions containing paraffins and volatile hydrocarbons can be economically reprocessed with heavy-oil dehydration facilities to recover residual hydrocarbons and to achieve volume reductions. The main factors affecting the use of this alternative are (1) the characteristics of the sludges requiring treatment, (2) the availability of waste heat or existing high temperature (>350°F) dehydration facilities, (3) air emissions from the process, and (4) effluent criteria for treated residues. This paper discusses operational variables that affect high-temperature reprocessing (HTR) and illustrates an application of the process. The example pilot project evaluated the feasibility of high-temperature reprocessing for tank-bottom sludges and skim oils from Kern County, CA, light- (>30°API) oil-producing leases. The process performance was quantified in terms of general operating parameters (flash point and paraffin, oil, water, and solids content); specific constituent analyses for benzene, toluene, ethylbenzene, and xylene (BTEX); and analyses for total petroleum hydrocarbons (TPH) content. Information on the percent removal of these parameters, characteristics of the treated residues, and the hydrocarbon recovery efficiency of the process are presented.
Numerical Simulation of Coning Using Implicit Production Terms
Authors: Spivak A. , Coats K.H.
Published: December 2007

This paper describes the use of a multiphase, multidimensional mathematical model to predict two- and three-phase coning behavior. Severe computational instability in the form of saturation oscillations in grid blocks near the wellbore is commonly encountered in the mathematical simulation of coning. This instability is due to the explicit (dated at the beginning of a time step and held constant for that time step) handling of saturation - dependent transmissibilities and production terms in the finite-difference solution of production terms in the finite-difference solution of the flow equations. An analysis of stability with respect to explicit handling of saturation-dependent transmissibilities is presented in this paper. This analysis shows why explicit transmissibilities can result in a severe time-step restriction for coning simulation. The use of implicit production terms in the difference equations to reduce instabilities is discussed and examples are given. These examples show that the implicit handling of production terms alone can result in a fivefold increase and permissible time step for a coning simulation with virtually no increase in computing time per time step. A laboratory water-coning experiment was simulated and excellent agreement was obtained between computed and observed results. A three-phase coning example for a gravity-segregation reservoir is also presented.

Introduction

Simulation of coning behavior is normally done by numerically solving the flow equations expressed in cylindrical (r, z, theta) coordinates with symmetry in the theta direction. The finite-difference technique of numerical solution of differential equations requires that the portion of the reservoir being simulated be divided into grid blocks as shown in Fig. 1. Since coning is a well phenomenon and not a gross reservoir phenomenon, the grid blocks must necessarily be relatively small in the vicinity of the wellbore because both pressures and saturations vary rapidly in this region. Severe computational instability is commonly encountered in the simulation of coning due to the relatively small grid-block sizes and high flow velocities in the vicinity of the wellbore. During a time step that would be considered normal for most reservoir simulation problems, a block near the wellbore is required to pass a volume of fluid many times its pore volume.

SPEJ

P. 257
Aromatic Recovery Unit: A Process Enhancement for Glycol Dehydrators
Authors: Choi M. S. , Spisak C. D.
Published: December 2007

A process enhancement to the standard glycol dehydration unit (GDU) was developed to recover hydrocarbons (including the aromatic compounds) normally vented with vapor during glycol regeneration. The gaseous hydrocarbons are recovered as a condensate product (stock-tank oil) and regenerator fuel. This paper describes the technology and proposes a proactive compliance strategy with the U.S. Clean Air Act Amendments (CAAA).
Permeability of Stylolite-Bearing Chalk
Authors: Lind Ida , Nykjaer Olav , Priisholm Soren , Springer Niels
Published: December 2007

Permeabilities were measured on core plugs from stylolite-bearing chalk of the Gorm field in the Danish North Sea. Air and liquid permeabilities were measured in directions parallel to and perpendicular to the stylolite surface. Permeability was measured with sleeve pressure equal to in-situ reservoir stress. Permeabilities of plugs with stylolites but without stylolite-associated fractures were equal in the two directions. The permeability is equal to the matrix permeability of non-stylolite-bearing chalk. In contrast, when fractures were associated with the stylolites, permeability was enhanced. The enhancement was most significant in the horizontal direction parallel to the stylolites.

Introduction

Stylolites are common in North Sea Chalk reservoirs (Albuskjell, Tyra, Ekofisk, West Ekofisk, Dan, and Gorm, Fig. 1). Typical stylolites of the Chalk have amplitudes of <1-cm size and clay-bearing drapes of <1-mm thickness. Stylolite-associated leaching, which can be prominent in limestones, has not been reported in the Chalk. In some reservoir intervals, stylolites are associated with fractures. These stylolite fractures commonly terminate against stylolite seams, perpendicular to or at least at high angles to the stylolite surface (Fig. 2). These fractures are 0.5 to 5 cm long and 0.01 to 0.1 mm wide.

In the Gorm field, stylolites are common with a vertical density of two to four stylolites per foot. Densities up to 20 stylolites per foot have been noted. A decreasing stylolite density is observed as porosity increases (Fig. 3). A similar trend was noted in the Upper Cretaceous chalk of England.

The influence of stylolites on effective permeability has been discussed by several authors. The consensus, based on petrography, is that stylolites in North Sea chalks act as barriers to flow in the vertical direction owing to their planar horizontal fabric and concentration of clay minerals. Flow in the horizontal direction may be enhanced if open fractures are associated with the stylolites. The present study does not support the assumption that stylolites form vertical barriers.

Actual measurements of stylolite permeability are few. One reason is that plugs tend to break along stylolite surfaces during drilling and routine core analysis, rendering them unsuitable for permeability measurement.

The objectives of this work were (1) to determine whether reliable measurements of permeability across and along stylolites are possible and, if so, under what test conditions; (2) to determine the influence of stylolites on the permeability of the chalk; and (3) to examine the relationship among stylolite-affected permeability, petrography, and mineralogy.
Reservoir Anisotropy Determination Using Multiple Probe Pressures
Authors: Head E.L. , Bettis F.E.
Published: December 2007

Wireline formation testers are commonly used to produce a profile of pressure vs. depth through a reservoir by performing a series of point pressure tests during one descent in the well. A new test tool which can conduct a number of controlled pressure interference tests between multiple probes produces a profile of permeability anisotropy vs. depth. Anisotropy, the ratio of vertical to horizontal permeability, is one of the parameters required to predict production performance. The 70 cm vertical separation between probes provides this information on a more macroscopic scale than core plugs. This paper defines the practical operating domain for multiprobe tests, and gives field examples to illustrate environments ranging from high to low permeability, with both large and small anisotropy. Repeatability and interpretation sensitivity are demonstrated.

Introduction

Reservoir anisotropy, here defined as the ratio of vertical to horizontal permeability kv / kh, is one of the parameters needed to predict production performance. A multiprobe wireline formation tester allows determination of both vertical and horizontal mobilities at specified test depths. The transient pressure responses at monitor probes displaced radially and vertically are measured while a controlled 1000 cc fluid sample is acquired through a sink probe. One objective of multiprobe testing is to provide a profile vs. depth of permeability anisotropy. The 70 cm separation between sink and vertical probes provides this anisotropy index on a more macroscopic scale than core plugs, which typically represent only a 2.5 cm sample.

This paper defines the conditions which can limit multiprobe operation and interpretation, and presents field examples which cover a wide range of environments. The examples illustrate high horizontal permeability with good vertical permeability, high horizontal permeability with low vertical permeability, and low horizontal permeability with a wide range of permeability anisotropy. Repeatability and interpretation sensitivity are demonstrated.
An Integrated Approach to Drilling in the Gulf of Mexico
Authors: Peery Michael D. , Bullock R.D.
Published: December 2007

This case history reviews the results of a single well and subsequent geological sidetrack drilled under an integrated partnering approach in East Cameron Block 306 of the Gulf of Mexico. The project demonstrates the benefits of partnering relationships. The integrated partnering approach proved to be an efficient and cost-effective means for the operator and service company to achieve objectives.

Introduction

The well, East Cameron Block 306 No. A-3, is located about 110 miles offshore Louisiana (Fig. 1). The operator had two wells on the structure drilled in 1990 and 1991, respectively, and wanted to evaluate the merits of using an integrated partnering approach to drill subsequent wells. Both offset wells were drilled recently using modern technology and equipment similar to that being proposed for a new well to be drilled under an integrated partnering approach. Because the operator had drilled two wells on the platform, a comparison of results could be made easily. The operator was able to get a quantitative cost comparison between wells drilled under a traditional format and wells drilled with an integrated partnering approach.

The operator believed that synergy could be achieved, resulting in advantages in both the planning and execution phases of the well. Specific advantages identified were the opportunities to access underutilized service company expertise and assistance, to establish common goals and objectives, and to reduce administration and prognosis development time and cost. In addition, through total project immersion, this "team approach" would make the service company an active participant, rather than a traditional vendor (Fig. 2). It was recognized that participant involvement and open communication at all levels - from the planning stage through project completion - creates synergy and esprit de corps.

Historical operator/vendor relationships are being re-evaluated throughout the industry, with partnerships, strategic alliances, and cooperative relationships now being seen as a more mutually beneficial means of conducting business.
Settling Velocity of Irregularly Shaped Particles
Authors: Chien Sze-Foo
Published: December 2007

A new correlation has been developed to predict the settling velocity of irregularly shaped particles in Newtonian and non-Newtonian fluids for all types of slip regimes. The correlation was derived from extensive data on the drag coefficients and particle Reynolds num-bers of irregularly shaped particles. The effective fluid viscosity at the settling shear rate is used in the correlation. A trial-and-error or numerical iteration method is required to predict the settling velocity for non-Newtonian fluids. The correlation predicted and verified the effects of fluid properties, particle properties, and operation parameters on the settling velocity.
Pulsed Neutron Capture Log Interpretation In Laminated Formations: A Dual-Exponential-Decay Model
Authors: Haley R. A.
Published: December 2007

Industry standard shaly sand equations for pulsed neutron capture (PNC) logs are premised upon homogeneous formations. Many interlaminated sands and shales, however, may not appear as homogeneous mixtures to PNC logs, despite the fact that the laminations may be very small (3 or 4 in.) and well below the vertical resolution of the PNC device. This can result in serious interpretation errors leading to bypassed pay. Log response equations and interpretation techniques for inhomogeneous formations are derived in this report and compared with a large sampling of observed data in river-dominated delta fringe sands of the Louisiana Gulf Coast. The excellent agreement warrants consideration of the new PNC log equation over the current industry standard equation as the primary method of evaluation in this type sandstone. The response of the natural gamma ray log to shaly sandstones is also reviewed. Possible misapplication of the industry standard PNC equation in deriving gamma ray/shale volume relations for inhomogeneous laminated formations is illustrated. The resulting impact on log interpretation is examined, and more appropriate relations are discussed.
Texas Offshore Bidding Patterns
Authors: Crawford Paul B.
Published: December 2007

If bids on offshore leases are determined by competent people, each acting independently and all evaluating each tract on the basis of the same criteria, what would be the general characteristic of the bids? An analysis of the bids on several tracts reveals that a pattern can be anticipated if the many factors involved are individually scrutinized beforehand.

Introduction

Half a billion dollars in bonuses was paid at only one offshore oil and gas lease sale last year. For each tract the cost of the bids ranged up to $43 million, and the number of bidders ranged from one or two to more than a dozen. The quality of the prospects varied widely and was reflected in both the bids and the number of bidders. In an effort to account for this variation, the bids on several tracts from a recent Texas sale have been analyzed. Many factors enter into the deliberations and formulation of a large sealed bid. All factors believed to affect the value of the property must be considered; these factors can be estimated with varying degrees of certainty. Among intelligent bidders the estimate of any single factor will vary and will always be uncertain; and the uncertainty will depend upon the individual. The "eternal optimist" in an organization may be inclined to estimate too highly, which could result in the acquisition of the property even though it might be of little financial merit. It will also result in the bids being too high from the bidding standpoint; that is, the next highest bid would be considerably lower. With this in mind, we intend to postulate how sealed bids on the offshore properties should be distributed.

Basic Premise

In arriving at the proposed distribution of bids it was postulated that competent earth scientists were to postulated that competent earth scientists were to make completely independent appraisals of an offshore prospect. Commencing with this premise, it is not difficult to arrive at the expected distribution of bids on a single tract. We are led to expect a straight-line correlation of bids when they are plotted in a certain manner. The present worth of a prospect may be arrived at by an independent decision based on the many factors affecting the bid on a property. This could be formulated in simple algebra as follows:

Sealed Bid (number of pays) × (average pay thickness) × (average length of reservoir) × (average width of reservoir) × (fraction of pore space occupied byby hydrocarbons) × (fraction recovery) × (average profit per Mcf of gas orbbl of oil produced) × (discount factor) × (expected occurrence of finding oilor gas,)..................... (1)

In simple language we shall say that the bid comes from the product of the many factors above, or

(1a)

The terms A, B, C, etc., represent a single bidder's estimate of the number of pays, pay thickness, etc., required to satisfy all terms in Eq. 1.

JPT

P. 283
Creation and Application of Multidisciplinary Teams in the Regulated Natural Gas Storage Business
Authors: Fay W.C. , Egden J.G.
Published: December 2007

Union Gas Ltd. is Canada's largest operator of underground natural gas storage facilities, with more than 126 Bcf of working capacity in southwestern Ontario. Recent advancements in E&P technology (3D seismic, reservoir simulations) have been applied successfully to storage. This technology has revealed a high degree of complexity in storage reservoirs that previously were considered relatively simple systems. Critical to the success of this technology transfer was the creation and management of multidisciplinary teams. Teams were small initially but have grown to include service companies and consultants from the planning stages through final project evaluation. Evolution of the team approach has resulted in faster, more cost effective and detailed projects. This paper presents specific team projects and case studies illustrating the difficult transition to the team approach in an extremely traditional, conservative environment.

Introduction

The establishment of multidisciplinary team environments has been common and successful within the upstream oil and gas industry for many years. Over the past 10 years, utility companies in Canada and the U.S. have experienced significant changes in terms of deregulation. In this changing marketplace, gas utilities have become more aware of their environment, developing markets external to their franchise areas and more aggressively developing transportation and storage projects. These challenges make multidisciplinary teams a necessity in the new and expanded market. Multidisciplinary teams have evolved to become the vehicle of choice for achieving a time-efficient and cost-effective position in a competitive market.

Union's storage reservoirs are all Silurian Age pinnacle reefs of the Guelph formation in Lambton County (Figs. 1 and 2). The areal extent of the reservoirs ranges up to several hundred acres. Well spacing ranges from 1,500 to 300 ft. The high well density, unlike production reservoirs, is necessary to ensure complete seasonal inventory turnover and to meet high peak daily demands in the winter at relatively low inventory levels. These reefs are ideal for storage because of their high permeability and porosity and a "super caprock" top seal.
An Object-Oriented Approach to Simulator Postprocessing
Authors: Leach B. F. , Scherer P. W. , Starley G. P.
Published: December 2007

An interactive, graphical software package provides the ability to view production well data generated by reservoir simulation. The program (KEYPLOT-X) includes several novel concepts, such as use of object-oriented technology for graphical software and a direct-access database structure. The entire application is constructed from a library of elemental objects. Inheritance of properties between objects produces extremely modular code, which greatly enhances maintenance and extendibility. The database has a direct-access hierarchical structure that is object-oriented, simplifying the data access protocol to provide rapid interactivity between the database, applications, and user interface. The overall approach has provided a high degree of functionality and flexibility to engineering applications and a manageable software structure for maintenance and development.
An Interactive 3D Mesh Builder for Fluid Flow Reservoir Simulation
Authors: Guérillot D. R. , Swaby P. A.
Published: December 2007

An original 3D-mesh builder designed to allow users to construct meshes interactively for fluid-flow simulation from a high-resolution geologic model is described. Most available packages use a series of horizontal and vertical 2D sections to build these meshes. Then, 3D visualizations sometimes are created to check the consistency. Our software incorporates a new approach to this problem by making better use of the geologic description, constructing the mesh directly in 3D, and introducing more flexibility in the individual cell geometry.
Incorporating Historical Data Into Monte Carlo Simulation
Authors: Murtha James A.
Published: December 2007

This paper demonstrates how to incorporate historical data into Monte Carlo simulations, describes how the parameters are distributed, and quantifies dependencies among them. It also shows the effect of ignoring dependency and presents summary statistics on field data.
A Practical Artificial Intelligence Application in EOR Projects
Authors: Elemo R. O. , Elmtalab J.
Published: December 2007

Two knowledge-based expert systems and a FORTRAN computer program were developed to aid the reservoir engineer in selecting appropriate EOR method(s), determining the quantity(ies) of recoverable oil, and evaluating economic feasibility of the selected method(s) for candidate reservoirs. Testing and sensitivity analyses showed that the developed expert systems are reliable and consistent with human experts' opinions. The expert systems were designed to accommodate new knowledge and technology that may emerge and become available in the future.
Nodal Systems Analysis Using Object-Oriented Programming Techniques
Authors: Takács Gabor , Turzo Zoltan
Published: December 2007

Efficient design of a flowing or artificially lifted well requires analysis of its components in conjunction with the entire system. These analyses customarily are called nodal systems analyses. Development of computer programs for nodal systems analysis is a complex and time-consuming task, mainly because of the complexity of the system. A recently emerging programming technique, object-oriented programming (OOP) can give programmers an excellent means for solving such difficult problems. The aim of this paper is to show the use of OOP programming techniques in the development of a computer program for nodal systems analysis. The program described here was written in TURBO PASCAL 6.0, and its menu system was created using Turbo Vision.
Improving Computer Simulation Through Use of a Graphical User Interface
Authors: Fife Leslie D. , Henry Stephen R.
Published: December 2007

Historically, simulation has been performed on large mainframe and minicomputers. These computers were limited in number, expensive, and controlled by a small group of professionals highly trained in the use of these resources. These resources were often difficult to access and use; they were not "user friendly." The appearance of high-speed, high-capacity desktop computers allowed an increasing number of engineers and scientists access to computers and simulators. Because these new resources were often difficult to use and the users were not highly trained, however, many of the problems associated with difficulty of use remained.

Graphical User Interfaces (GUI's) have helped solve many of the usage problems. GUI's provide additional capabilities that increase the ability of scientists and engineers to use their computer resources. These capabilities increase the value of simulators by extending usage through increased functionality. The consistency of a well-designed family of simulator GUI's can enhance training effectiveness by increasing familiarity with basic operations, assisting in the validation of data, and improving "help" facilities available to the user.
Concept of Gravity Drainage in Layered Porous Media
Authors: Corrêa Antonio Cláudio F. , Firoozabadi Abbas
Published: December 2007

Gas-oil gravity drainage in layered porous media is, under certain conditions, an unstable process. Even for two layers, gas could finger through a less permeable top layer to reach a more permeable bottom layer.

This paper provides a criterion for instantaneous gas fingering towards the more permeable layer. A non-linear form of the diffusivity equation is used to study gas-oil drainage in layered systems. Numerical examples show that recovery performance of layered systems, unlike homogeneous media, is sensitive to capillary pressure.
A Comparison of Several Methods for Automated Well Test Analysis
Authors: Vieira P. M. F. , Rosa A. J.
Published: December 2007

This paper presents a comparison of several nonlinear parameter estimation methods for automated well test analysis. Methods based on either the L2-norm or the Li-norm were considered The techniques based on the minimization of the L2-norm were the least squares (LS) and the singular value decomposition (SVD) methods. The nunimizauon of the Li-norm included the least absolute values (LAV), the modified least absolute values (MLAV) and the combination MLAV-LAV. Important characteristics of these methods were discussed such as: constrained optimization, statistical analysis of the estimation results and error probability distributions. A new approach to constrain the optimization process was proposed An analysis of the use of pressure data, pressure derivative data and pressure and pressure derivative data as model functions was performed.
Void Fraction in Bubbly and Slug Flow in Downward Vertical and Inclined Systems
Authors: Hasan A. R.
Published: December 2007

Much work has been done in the area of two-phase upflow, while the flow of gas and liquid in the downward direction has not received much attention. This paper presents a model for estimating void fraction in downward flow for vertical and inclined systems for the two dominant flow regimes, bubbly flow and slug flow. We use the drift-flux approach to determine slip between the phases and the transition between the flow regimes. The flowing mixture densities calculated from the model are useful for pressure gradient estimation.

Extensive data are used to validate the model. The data show that for both bubbly and slug flow the effect of buoyancy, expressed by the terminal bubble-rise velocity, has the same magnitude as that for the case of upflow. In addition, the flow distribution parameter in bubbly flow appears to have the same value of 1.2 as in upflow. For slug flow, however, the flow parameter is represented by a somewhat lower value (1.12) than for upflow.
Hydrate Inhibition Design for Deepwater Completions
Authors: Davalath J. , Barker J. W.
Published: December 2007

This paper will review the design considerations for gas hydrate prevention in deepwater well completions. The influence of seafloor temperature, wellbore pressure, water production rate and composition of gas on hydrate inhibition system design will be discussed. The impact of various inhibitors will be discussed in relationship to the design of the system and potential handling problems. Examples will review design considerations for sizing of subsea inhibitor lines, selection of injection depth below the seafloor and hardware requirements. Case histories of inhibitor injection systems used in deepwater completions and during testing of deepwater exploration wells will be reviewed. The benefits of insulated tubing to enhance inhibition design will be discussed. Also, a method will be introduced that can be used to estimate the maximum inhibitor injection rate to avoid salt precipitation from completion fluid or produced water.
Practical Automation for Mature Producing Areas
Authors: Luppens J. C.
Published: December 2007

Successful installation and operation of supervisory control and data acquisition (SCADA) systems on two U.S. gulf coast platforms, prompted the installation of the first SCADA, or automation, system in Oklahoma in 1989. The initial installation consisted of four remote terminal units (RTU's) at four beam-pumped leases and a PC-based control system communicating by means of a 900-MHz data repeater. This first installation was a building block for additional wells tobe automated, and then additional systems, consisting of RTU's, a PC, and a data repeater, were installed. By the end of 1992 there were 98 RTU's operating on five separate systems (Fig. 1), and additional RTU's are being installed on a regular basis.

The tangible and intangible savings generated by these automation systems have exceeded expectations in all cases. Downtime has been reduced by up to 83%, surface maintenance costs on beam- pumped wells have been reduced by an average of 40%, and the cost of well workovers for rod, tubing, and/or pump repairs has been reduced by 17% to 44%, depending on field conditions. These improvements have led to production increases of up to 30%. Additionally, spills have been significantly reduced and early detection of leaks, when they occur, has reduced the impact of these spills, enhancing the environmental compatibility of operations.

This paper outlines the logical development of automation systems on properties in Oklahoma operated by Phillips Petroleum Co. Those factors critical to the success of the effort are (1) designing data-gathering and control capability in conjunction with the field operations staff to meet and not exceed their needs; (2) selection of a computer operating system and automation software package; (3) selection of computer, RTU, and end-device hardware; and (4) continuous involvement of the field operations staff in the installation, operation, and maintenance of the systems. Additionally, specific tangible and intangible results are discussed.
An Evaluation of Prudhoe Bay Horizontal and High-Angle Wells After 5 Years of Production
Authors: Pucknell J.K. , Broman W.H.
Published: December 2007

Based on 5 years of production history on 14 horizontal and high-angle wells, this paper reviews the performance of these wells compared with conventional offsets, discusses how shales influence GOR's, describes production log and well test interpretation, gives evidence that only parts of the horizontal section actually produce, and describes the success of coiled-tubing workovers.

Introduction

The Prudhoe Bay field is the largest Alaskan oil field. BP Exploration operates the western half, which is the subject of this paper. Production is from the Ivishak sand stone, a layered reservoir of variable properties, including high-permeability fluvial conglomerates and lower-permeability sand stones. The average sand/shale ratio is 0.9, and the shales are a major factor controlling well performance.

The first horizontal well in the western area of the Prudhoe Bay field was drilled in Nov. 1985. Since then, BP has drilled a number of horizontal and high-angle wells. This paper discusses the first 14 of these wells. They have been on production for an average of about 5 years. These wells, with deviations greater than 82, are called non conventional wells (NCW's) and are listed in Table 1.

The wells can be split into two groups: 10 wells located below the original gas cap in the gravity-drainage area, where high GOR's cause problems, and 4 wells in the peripheral and west end areas (see Fig. 1), where water cuts can be significant.

By 1992, a large amount of information had been accumulated. This paper is the result of a review of that information-production histories, production logs, pressure-buildup tests and coiled-tubing workovers. Drilling and reservoir simulation are not covered.

Cumulative Oil Produced by NCW's Compared With Offsets. To establish the benefits of NCW's, the cumulative oil produced by NCW's was compared with that produced by offset conventional wells (0 to 60). Offset wells chosen as analogs were completed in the same zone at a similar time and had no known mechanical problems (e.g., cement channels). Table 2 gives the results. These comparisons show that overall the NCW program has been a considerable success, recovering an extra 21 million STB of oil. Although some of this oil may have been produced at the expense of offset wells, it is still a large incremental volume. How ever, 5 of the 14 wells do not currently show any benefit in terms of additional oil produced compared with analogous conventional wells. Efforts were made to establish why some wells were more successful than others.