bluuebunny/crossref_metadata_2025 huggingface dataset:
An Evaluation of Procedures to Estimate Uncertainty in Hydrocarbon Recovery Predictions
Authors: Chewaroungroaj Jirawat , Varela Omar J. , Lake Larry W.
Published: December 2007

It is widely recognized that predictions of hydrocarbon recovery are uncertain. In the area of reservoir engineering, the sources of uncertainty have three major causes: 1) the model, because it is an imperfect representation of reality, 2) geologic parameters, because of a limited sampling in space and/or time, and 3) measurement errors in the experiments performed to determine inputs. Thus, a statistical treatment that recognizes both the lack of knowledge and the uncertainty of the parameters involved in the forecast of reservoir performance is desirable. Current stochastic-modeling approaches (Monte Carlo simulation and geostatistics) require extensive computational effort for realistic problems. There are numerous reasons for this, but the one that seems to present the largest hurdle is that reservoir predictions require a large number of input parameters. The thrust of this work is to find ways to perform uncertainty predictions with fewer parameters.

This paper demonstrates several approaches that quantitatively estimate uncertainty in specific hydrocarbon-recovery predictions. These approaches include scaling, firstorder and second-order analyses, response surface, and the Taguchi and Box-Behnken experimental designs. Numerical reservoir simulations were performed in two hypothetical reservoirs using each of the above methods to estimate uncertainty in oil-recovery efficiency. Results from these techniques are compared to experimental design and Monte Carlo simulations. The combination of scaling and the Box-Behnken experimental design can provide a reasonably accurate uncertainty estimation of hydrocarbon recovery with fewer simulation runs than the Monte Carlo simulation. In addition, we successfully reduced the turnaround time of the Monte Carlo simulation runs by using clusters in parallel of personal computers instead of one computer (e.g., more than 10 times faster with a cluster of 16 PCs).

Experimental design and the use of multiple processors will reduce the computational effort in estimating uncertainty of a hydrocarbon-recovery prediction. This combination would also give rise to the possibility of exploring several existing methods in the design of experiments to lessen the burden of performing numerous large reservoir simulations.
Compaction of Argillaceous and Coarse-Grained Sediments
Authors: Rieke Herman H. , Chilingar George V. , Fertl Walter H.
Published: December 2007

During the past quarter century, the exploitation of oil and gas reserves, associated with thick sequences of very fine-grained and coarse-grained rocks in Tertiary basins, have become increasingly important for fulfilling the world's energy needs. Many exploration and reservoir development problems have arisen which demand an analytical solution. The scientific problems have arisen which demand an analytical solution. The scientific and technological problems associated with these geologically young basin sediments include the origin, maintenance and distribution of abnormally high pore-fluid pressures, chemical changes induced in the interstitial water by compaction, origin and migration of hydrocarbons, temperature gradients, clay minerals phase changes and subsidence of the surface. Successful drilling to depths greater than 20,000 feet in these sediments and the amounts of the hydrocarbons discovered and produced depend to a great extent on our knowledge of the physical and mechanical properties and deformation characteristics of the sediments and the interrelationships between their various petrophysical and fluid properties. This paper is an historical review of studies dealing with the effects that gravitational compaction of sediments has on hydrocarbon reservoirs and source beds. Specific attention will be given to the generation of abnormal pore-fluid pressures, chemistry of interstitial fluids, compaction models, pressures, chemistry of interstitial fluids, compaction models, compressibility of the reservoir rocks and surface subsidence.

Introduction

It has been postulated that gravitational compaction of sediments is directly related to the following parameters and can be functionally represented in the following manner:

C = (1)

Where C is the degree of compaction, is the stress on the sediment system, is the velocity parameter for solids and interstitial fluids in the system, is the density, is the bulk volume of the sediments, is the porosity, is the permeability of the system, is the burial depth, t is the time, T is the geothermal temperature, and c represents the compressibility relationships.

Gravitational compaction of sediments under the influence of their own weight has long been a recognized geologic phenomenon. In the seventeenth century Steno attributed variations in the attitude of sedimentary formations to compaction.
Sequential Scale-Up of Relative Permeabilities
Authors: Suzuki K. , Hewett T. A.
Published: December 2007

This paper presents a new method for scaling up multiphase flow properties which properly accounts for boundary conditions on the upscaled cell. The scale-up proposed does not require the simulation of a complete finely-gridded model. Instead it introduces assumptions allowing the calculation of the boundary conditions related to each block being scaled up.

To upscale a coarse block, we have to assume or determine the proper boundary conditions for that coarse block. To date, most scale-up methods have been based on oversimplified assumptions such as steady-state flow associated with uniform fractional flows over all the boundaries of the coarse block. However, such an assumption is not strictly valid when we consider heterogeneities.

The concept of injection tubes is adopted: these are hypothetical streamtubes connecting the injection wellbore to all inlet faces of the fine grid cells constituting the block to be scaled up. Injection tubes allow the capturing of the fine-scale flow behavior of a finely-gridded model at the inlet face of the coarse block without having to simulate the full fine grid. We describe how to scale up an entire finely-gridded model sequentially using injection tubes to determine the boundary conditions for two-phase flow.

This new scale-up method is able to provide a coarsely gridded model which can reproduce the spatially-averaged performance of the finely-gridded model reasonably accurately. The method has been shown to be applicable not only to viscous-dominated flow but also to flow affected by gravity for reasonable viscous-to-gravity ratios.
Historical Problems with Old Field Rejuvenation
Authors: Blaskovich F. T.
Published: December 2007

In many parts of the world, the redevelopment of older fields presents unique problems that will require innovative solutions. With the rising costs of finding and developing new oil fields, oil companies are turning more attention to revitalizing existing fields. Because of historical practices, these fields often have significant potential for enhanced recovery. These older fields have many different problems to deal with than the more modern fields that traditionally drive petroleum technology.

Advances in computer hardware and software technology have made it possible to analyze reservoirs at a level of detail unimagined only a few years ago. With all of this power on our desktops, it is easy to lose sight of a major problem in dealing with older fields – the historical data.

In many cases, there may be a large amount of historical data, but much of it is either inaccurate or critical types of data have not been gathered. Several field examples are discussed in this paper. Each field has redevelopment potential using modern techniques, but each project has great uncertainty due to data constraints. The conclusions and recommendations of the paper include suggestions for ways to solve these problems. Since we cannot go back in time to gather critical missing data (e.g., early production and injection data, initial fluid properties, produced compositions, etc.), special techniques will be needed to determine the value of these projects.
Using Crosshole Electromagnetics (EM) for Reservoir Characterization and Waterflood Monitoring
Authors: Patzek Tadeusz , Wilt Michael , Hoversten G. M.
Published: December 2007

The crosshole EM technique provides an image analogous to a smoothed two-dimensional induction resistivity log. Inductive EM sources are placed in one well and magnetic field receivers in a second well, up to a km away. Sources and receivers are positioned above within and below the depth interval of interest, and we image the resistivity of the interwell volume to fit the collected data. Data may be collected in open and/or steel-cased boreholes, although steel casing reduces this range. The resolution of images is roughly 5 percent of the well spacing.

The technique has been used for more than 5 years in imaging thermal oil recovery operations, but more recently for reservoir characterization and water flood imaging. The resistivity contrast between salt water saturated zones and oil and gas pay zones usually provides an excellent signal for the EM data and makes the imaging of the water flood fairly straightforward.

In this paper we provide a technology overview and then show a case history where the EM resistivity images have defined the initial water saturation distribution, and have tracked changes over a two year period due to water flooding in a fracture dominated southern California reservoir. We further describe simulations for crosshole EM imaging in carbonates for a WAG (water alternating gas) process where the technique is used for initial site characterization and to monitor saturation changes during the injection.
Technology Integration of Conformance and Magnetic Resonance Imaging Enhances Stimulation Treatment
Authors: Soliman M. Y. , Creel Prentice , Rester Stephen , Sigal Richard , Haest James , Azari Mehdi
Published: December 2007

Although fracturing is an established technology with a wide range of usage, certain reservoir scenarios that appear to be good candidates for its application do not benefit from its usage. Examples of these reservoirs include stratified wells in which some of the layers are water-bearing formations or scenarios where an aquifer is present and the fear of breaking into the water zone exists.

By combining the techniques developed in the magnetic resonance imaging (MRI) and conformance technologies, accurate identification of reservoir conditions can be made, and a fracturing approach that can enhance oil production and reduce or even eliminate water production can then be designed and successfully implemented.

The success of this approach depends on several factors. The first is an accurate description of the reservoir. Without this, it is not be possible to accurately assess the underlying reasons for the water production problems so that the appropriate stimulation design or remedial treatment can be applied.

The importance of using the proper diagnostic tools and techniques is, therefore, of extreme importance when determining what remedial applications should be considered. These tools must determine the type and the location of reservoir fluids as well as whether the encountered water is mobile. Presently, only one technology, MRI, can fulfill all these needs. The tool developed to target this technology is an openhole MRI logging tool that operates on magnetic resonance imaging principles. This tool plays a major role in the successful application of conformance technology.

This paper provides an in-depth discussion on how the concept of coupling fracturing, conformance and MRI technology has been made possible through the application of MRI logs. Simulated examples, created using a commercially available 3-D, 3-phase numerical simulator, will be used to illustrate the technical enhancements and economic value that can be derived through use of this technological integration.

Actual field cases performed in the Permian Basin will be presented and discussed. The cases described in this paper show the extent of the technical and economical successes achieved using this technology.
Innovations in Slickline Technology
Authors: Arnold R. Stephen
Published: December 2007

The ability to perform such services as Production Logging and Perforating are now available on Slickline. With Today's technology any number of operations can be achieved more cost effectively and with greater ease than ever before. Comparison with Fiber Optic and Electric Line has proven that the expected results will rival those of real time logging.
New Methods for Determining Formation Properties from Stabilized and Unstabilized Gas-Well-Test Data
Authors: Satman Abdurrahman , Onur Mustafa , Tureyen Omer Inanc
Published: December 2007

In this paper, new explicit analytical equations for stabilized and transient deliverability coefficients in terms of formation/fluid parameters are presented. These equations are derived for fully and partially penetrating vertical wells and for fully penetrating horizontal wells. The proposed equations use the relationship between the empirical (Rawlins and Schellhardt) deliverability equation and rigorous (or Forechheimer's) deliverability equations for both stabilized and unstabilized (transient) flow conditions. Based on these new equations, we also present new methods for determining not only the performance coefficients, but also formation parameters from stabilized and transient gas deliverability data. Unlike the existing methods, our new methods do not require geometric mean of pressure or rate data. This is a distinct advantage of the methods presented in this paper over the existing methods because determination of geometric mean of pressure or rate data may be quite difficult, and the mean value is quite sensitive to the measurement errors in such data. Thus, the methods given in this paper should prove very useful for determining formation parameters accurately from deliverability tests in vertical and horizontal wells. The accuracy and applicability of the methods given in this study are verified by analyzing two test data published previously in the literature. Results are compared with those obtained from the existing methods in the literature and indicate that combination of our new methods with the Hinchman-Kazemi-Poettmann method for isochronal test types provides more information about the formation and reliable deliverability forecasting.
Use of Silicate Mud to Control Borehole Stability and Overpressured Gas Formations in Northeastern British Columbia
Authors: Stewart Michael R. , Kosich Bill , Warren Brent K. , Urquhart John C. , McDonald Michael James
Published: December 2007

A freshwater silicate based drilling fluid, containing 20-30% sodium silicate by volume, was successfully used to drill a gas well in northeastern British Columbia. Major drilling issues in the area include borehole instability in 500 plus meters of highly dispersible Ft. Simpson shale, high pressure gas zones and potential moderate-severe lost circulation.

Despite problems of severe lost circulation and high mud weights, the caliper log on the silicate well showed <1% hole enlargement over the Ft. Simpson shale and 12% enlargement over the entire intermediate section. Typical offset calipers with other water-based muds average 48% and 31% enlargement over the Ft. Simpson and entire well section, respectively.

Rates of penetration with silicate mud were generally better than offset wells. Uphole formations drilled to 1060 meters with a low solids, lower density silicate fluid (1195 kg/m3 mud density) drilled at an average of 19.2 m/hr. Offsets drilled with gel-chemical or gel-PHPA systems over the same interval normally averaged 12.6 m/hr.

This paper describes the planning and drilling of the first well with a drilling fluid containing silicates up to 30% concentration. Topics discussed include borehole stability, rates-of-penetration, motor performance, drilling fluid stability and properties, and environmental aspects of silicate disposal.
A Permeability-Dependent Dimensionless Inflow Performance Relationship Curve for Unfractured Gas Wells
Authors: Billiter Travis , Lee John
Published: December 2007

A dimensionless inflow performance relationship (IPR) curve that is a function of permeability has been developed for unfractured gas wells. Both numerical and analytical methods were used to solve the non-Darcy, gas flow equations. This analysis showed that the current dimensionless IPR curve for unfractured gas wells in pseudosteady-state flow is basically independent of all relevant variables, except permeability. The proposed current dimensionless IPR curve has the same general form as the familiar Vogel dimensionless IPR curve for solution-gas-drive oil reservoirs, with the coefficients of the proposed dimensionless IPR curve being a function of permeability. The proposed current dimensionless IPR curve can be used to predict the deliverability of a gas well using a single-point test, as opposed to a standard four-point deliverability test, if the permeability of the well is known. A future dimensionless IPR curve to predict future gas well deliverability that is a function of permeability is also presented. The time to reach pseudo-steady state flow for an unfractured gas well is two to three multiples of the time predicted by the commonly used, stabilization time equation.
Gas-to-Liquids Technology for Bunyu Field, East Kalimantan, Indonesia
Authors: Arianto Indria Doria , Siallagan Charles P.
Published: December 2007

Technology to converts natural gas into synthetic liquid fuels (the name is GTL, for Gas-to-Liquids) turns unmarketable reserves of natural gas into a form that overcomes transportation costs. Synthetic liquid fuels produced via Fischer-Tropsch (FT) chemistry, such as gasoline, kerosene/jet fuel, and diesel, have long been known as the cleanest fuels in the world. Unfortunately, the cost making them has never been competitive when compared to conventional process. Now, because of better catalysts and process improvement, FT may have finally found a competitive niche. Bunyu Island located off the Northeast coast of East Kalimantan, Indonesia, approximately 580 km north and East of Balikpapan. There are 10 existing fields in Bunyu Island managed by Pertamina. Bunyu-Nibung field was discovered with the drilling of well BN-01 in 1971, geologic evaluation discovered oil and gas reserves. Until now, 15 wells had been drilled and developed as oilfield although the gas reserve is large. This gas reserve undeveloped because of the limitations of gas markets. Based on 22 MMscfd feed gas for 20 years production, this technology can converting gas to 4,180 b/d synthetic fuel consist of gasoline 1,797 b/d, kerosene 477 b/d, middle distillate 765 b/d, and HSD 1,053 b/d. Economic calculation indicates that this technology considered economically with POT 3.11 years and IRR 47.42%. Although it is too remote for economic transportation, GTL would liberate Bunyu-Nibung gas reserves from the limitations of gas markets.
Friction Factor in High-Pressure Gas Pipelines in the North Sea
Authors: Sletfjerding Elling , Gudmundsson Jon Steinar , Sjøen Karl
Published: December 2007

Field data from capacity tests of long-distance gas pipelines in the North Sea have been used to model the friction factor in internal coated pipelines. The field measurements were compared to an experimental investigation of the friction factor in coated pipes performed in a high-pressure flow loop. A good correlation between the experimental data and the field data was obtained. It was found that the friction factor in the coated gas pipelines could be modelled by the Colebrook-White correlation with an equivalent sand-grain roughness of 1.5 μm. The results showed that internal coatings effectively reduce the pressure drop in gas pipelines and thus increase the transport capacity.
Phase Behavior of PCB-Contaminated Natural Gas
Authors: Nor-Azlan N. , Adewumi M. A.
Published: December 2007

Polychlorinated-biphenyl (PCB) contamination problems are prevalent in the natural gas industry especially in the pipeline transmission and distribution sectors. As a result of PCB disposal problems, many natural gas companies have been subjected to heavy fines. Considering the magnitude of the problem, the gas industry has taken the initiative to pursue a comprehensive remediation effort to cleanup pipeline and distribution systems contaminated with PCB. This study is a part of the remediation effort. This paper addresses the phase behavior of PCB-contaminated natural gas systems and explores how to utilize this information to attempt the formulation of remediation strategies. A model suitably designed for studying the problem has been developed. The model is used to investigate the distributive nature of PCB compounds and to analyze their effects on the overall phase behavior of the natural gas system. New quality line definitions are introduced for the purpose of tracing PCBs in the gas mixture. Some experimental results and model predictions are presented and discussed. A case study using actual field natural gas mixture is performed in order to demonstrate the capability of the model prediction. The study is important in assisting engineers and operators to design an effective remediation strategy to cleanup pipeline transmission and distribution lines contaminated with PCBs.
Completion and Fracture Modeling of Low-Permeability Gas Sands in South Texas Enhanced by Magnetic Resonance and Sound Wave Technology
Authors: Fairhurst D. L. , Marfice J. P. , Seim M. R. , Norville M. A.
Published: December 2007

Recent advances in logging technology have enabled development of a better rock model and better fracture design for low-permeability reservoirs. The new measurements also have improved in-situ analysis and the identification of productive zones that might otherwise be bypassed.

Sonic waveform and magnetic resonance technology enhances the standard logging platform by providing a more accurate shear modulus and permeability estimate. The accuracy is necessary for a better dimensional fracture model. The model appears reasonable for completions in the Olmos and San Miguel sands in south Texas. In some cases the magnetic resonance has identified previously bypassed permeable streaks that increased production. In other cases, sonic waveform technology has helped determine fracture direction, thereby enhancing gas drainage and well placement.

In this paper, field production results are correlated to the model. Less efficient designs based on minimal data are compared with designs having more complete data sets. Recent completion data confirm that better parameters can be obtained with the new measurements.
Matrix Acidizing in Gas Wells
Authors: Fadele O. , Zhu D. , Hill A. D.
Published: December 2007

Matrix acidizing treatments are applied to gas wells to remove near-wellbore permeability impairment (formation damage). The acidizing process differs in gas wells compared with oil wells or water injection wells because of two-phase, gas-liquid flow during acid injection, and also because of the relatively low viscosity of the gas. This paper demonstrates how these differences affect the penetration of acid into the formation and the distribution of acid along the wellbore (acid placement).

When acid displaces gas in the formation around the wellbore, the favorable mobility ratio between the acid and the gas will lead to a piston-like displacement of the gas by the acid. However, behind the acid front, a residual gas saturation will remain. Our study shows that the impact of the residual gas saturation increases acid penetration into the reservoir, when compared with a single-phase displacement process.

The large contrast between the viscosity of the acid and the gas in the reservoir may be beneficial to a better distribution of acid along the wellbore. Because the acid is much more viscous than the gas, there will be an increased pressure drop wherever acid is placed in the formation. This can function as a natural viscous diversion - as acid enters the higher permeability zones, the increased pressure gradient can divert relatively more acid to lower permeability zones. We present modeling results that illustrate the magnitude of the viscous diversion effect in gas wells. This natural diversion precludes the use of gels or other viscous fluids for diversion in gas wells.
Determination of Original Gas in Place in Ballycotton, Offshore Ireland
Authors: Chu Wei-Chun , Fleming C. H. , Carroll K. M.
Published: December 2007

This paper presents a new approach for determining OGIP early in the field life of an edge-water drive gas reservoir. The approach is applied to Ballycotton gas accumulation. Ballycotton was discovered in March 1989 adjacent to the nearby Kinsale Head Field, a major gas accumulation in the Celtic Sea, Ireland. Ballycotton and Kinsale Head have a common aquifer. Kinsale Head Field was put on production in 1978 using two platforms Alpha and Bravo. From July 1991, Ballycotton produced gas as a subsea-completed satellite of the Kinsale Head Field, tied back to the Bravo platform at Kinsale Head. A permanent gauge was installed on the subsea tree in 285 feet of water. Using continuous pressure and rate measurements, we routinely interpreted well data using superposition techniques. Within the first six months of production, an accurate estimate of original gas-in-place (OGIP) was established from the data. This is in contrast to the p/z versus Gp material balance approach, which is seldom accurate early in the life of the field.

This case history clearly illustrates the benefit of utilizing continuously measured pressure and rate data to obtain an accurate original gas-in-place early in a field's life. In addition, this paper demonstrates the benefit of permanently installed pressure gauges in subsea-completed satellite fields.
Application of Fracture Technology in the Hanoi Trough, Vietnam
Authors: Cipolla C. L. , Mayerhofer Michael , Wilson B. L.
Published: December 2007

This paper presents a detailed case history of the evolution of fracture technology in the Hanoi Trough, Vietnam. The target formations are stacked fluvial channel deposits that occur at depths of 10,000 to 12,000 ft with permeability ranging from to 1 mD. The first three wells drilled in 1996-97 were fracture stimulated, but only one of the three treatments was successful. Three more wells were drilled in 1999 and significant improvements in completion and hydraulic fracture technology were implemented. This paper presents a comprehensive data set, which includes the evaluation and integration of pre-& post-fracture well tests and log data with detailed fracture modeling analyses to understand and improve fracture performance in this complex environment.
Petroleum Sulfonate Utilization in Enhanced Oil Recovery Systems
Authors: Knaggs Edward A. , Nussbaum Marvin L. , Carlson James B. , Guenzani Robert C.
Published: December 2007

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

Petroleum sulfonates are currently being evaluated extensively in surfactant enhanced oil recovery processes in laboratory studies, pilot field trials, and in semicommercial field tests. Consideration of surfactant manufacturing, product availability projections, product properties and laboratory oil recovery tests among available types of petroleum sulfonates establish that those produced directly and economically from abundantly available petroleum refinery feedstocks can be petroleum refinery feedstocks can be produced in volume to meet oil industry produced in volume to meet oil industry requirements. The diversity of crude oils ana reservoir constraints make it desirable to tailor surfactant systems to optimize oil recovery.

Introduction

Most of the many hundreds of currently existing U.S. patents directed to surfactant enhanced oil recovery processes disclose the use of petroleum sulfonates singularly or in various surfactant combinations. In spite of this plethora of petroleum sulfonate use claims, the technical literature is almost devoid of comparative information relative to the various types of available petroleum sulfonate products — those derived as low yield sulfonation "by-products" and those by direct higher yield petroleum sulfonation in which the sulfonate is the primary product — and to processes for their manufacture. Accordingly, this paper, addresses itself to filling this need, with greatest emphasis being placed on the comparison between placed on the comparison between conventional petroleum mahogany sulfonates and the newer petroleum sulfonates produced by direct petroleum sulfonation recently developed by the present authors and their associates.

It is apparent that for the most part the oil industry's main technical thrust has been primarily directed towards developing the complex oil recovery process technology, whereas surfactant product and process development has been a secondary process development has been a secondary consideration, with some notable exceptions to be sure. While it has recently been reported (1) that crude oil sulfonate is now being produced by SO sulfonation, the resultant low yield sulfonate is directly converted to a dilute surfactant "slug" system and is thus beyond the scope of this study.
Effect of Chemical Treatment Upon Formation Clays is Revealed by Improved SEM Technique
Authors: Thomas R.L. , Crowe C.W. , Simpson B.E.
Published: December 2007

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

A number of commonly used stimulation and clay stabilization treatments have been investigated using an improved and more definite Scanning Electron Microscope technique. This technique involves photographing individual groups of clay platelets within a sandstone specimen at high magnification using the Scanning Electron Microscope and then chemically treating the sample. Following the treatment, the same set of platelets is located and again photographed under identical conditions of framing and magnification. By comparing the two SEM photographs, in addition to Energy Dispersive X-ray analysis of the platelets before and after treatment, it is platelets before and after treatment, it is possible to detect even minute changes in the possible to detect even minute changes in the structure and chemical composition of the clay minerals. The SEM technique used in these studies is described in detail.

Systems studied include clay stabilizing agents such as hydroxy aluminum and zirconium oxychloride. The effect of various acids including hydrochloric acid, Mud Acid and Self-Generating Mud Acid have also been investigated. These studies clearly show how chemical treatments modify the clays present within the rock. Test results indicate that clay stabilizing agents work by either ion exchange or topochemical reactions. Hydrolyzable metal ions such as zirconium and hydroxy aluminum may not form the same kind of layer on the surface of the clay, but both materials effectively desensitize the clays. Core test data correlates well with SEM.

Introduction

Swelling and migration of clay minerals in sandstone formations has long been a problem in oil and gas production. Dispersed problem in oil and gas production. Dispersed or swollen clays can plug-the narrow pore openings within the formation, thus restricting both liquid and gas flow. It is believed that dispersion and migration of formation clays isoactually a greater problem than clay swelling. The dispersion of a small amount of non-swelling but migratory clay can cause a much greater reduction in permeability than an identical quantity of a swelling clay. Kaolinite and illite are two of the most commonly occurring non-swelling migratory clays, while montmorillonite is the most common swelling clay.

Various treatments have been developed to prevent or minimize swelling and migration prevent or minimize swelling and migration tendencies of formation clays.
Analysis of Pressure Transient Data in Naturally Fractured Reservoirs With Spherical Flow
Authors: Ershaghi Iraj , Rhee Shie-Woo , Yang Hsun-Tiao
Published: December 2007

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

Methods for analysis of pressure transient performance in homogeneous reservoirs with performance in homogeneous reservoirs with spherical flow have been presented by others in the past. This work extends the art to the case of naturally fractured reservoirs with uniform fracture distribution. A reservoir model similar to the double-porosity system described by Warren and Root is employed. The fundamental differential equation and the solution of the equation by the application of the Laplace Transformation serves as the theoretical foundation.

A method is then presented for estimation of an average spherical permeability and static reservoir pressure. Also the procedure for estimation of total fluid capacitance (2C2+ 1C1) and the fraction of which being contributed by the fracture network () is discussed.

Introduction

If in a naturally fractured reservoir only a small interval of the upper portion of the zone is open to production, the flow regime has a vertical component and cannot be considered cylindrical. The existence of the vertical flow component gives rise to the establishment of a hemispherical flow system, Fig. 1.

The problem of spherical flow in homogeneous porous media has received a fair treatment by porous media has received a fair treatment by others. Muskat derived the general equation for potential distribution in a spherical flow system. He showed that for a steady state system under spherical flow the pressure gradients are much more concentrated about the wellbore than in the case of radial flow. He further noted that for such systems the flux is independent of the shape and the size of the drainage boundary as long as the external boundary radius is large compared to the wellbore radius. Moran and Finklea were the first to present the pressure buildup equations for analysis of pressure data obtained form wireline formation testers. They showed that for thin beds the early stages of pressure buildup tend toward spherical flow. The later stages, however, approach cylindrical flow.

Chatas considered several flow problems of importance to reservoir engineering where spherical geometry serves as a better approximation than the cylindrical.
The Development and Application of a Novel Scale Inhibitor for Deployment in Low Water Cut, Water Sensitive or Low Pressure Reservoirs
Authors: Collins I. R. , Jordan M. M. , Taylor S. E.
Published: December 2007

Water-in-oil emulsions have been developed which have been shown to be a credible means of deploying scale inhibitors in a non-aqueous medium. Furthermore, the use of slowly degrading emulsion systems provides a means of trapping scale inhibitor within porous media and allowing subsequent controlled release of the chemical. This has been demonstrated using sandpack and coreflood experiments where the lifetime of the inhibitor, as measured by pore volumes of brine eluted to a given inhibitor concentration, has been extended by up to (and possibly beyond) four times compared with the base case non-emulsified product. No permeability damage has been observed for the emulsion systems. The use of emulsion droplets to provide chemical reservoirs within the formation also considerably reduces the wastage of non-retained chemical observed with conventional squeeze treatments. The non-aqueous nature of the emulsion system potentially allows ingress of the scale inhibitor into parts of the reservoir normally denied access to an aqueous-based formulation and so can improve contact between the scale inhibitor and the reservoir fluids on production. Furthermore, the whole treatment can be non-aqueous allowing oil continuity to be maintained during the treatment affording rapid well clean up post treatment.
Simplified Performance Prediction Method for Vertically Fractured Gas Wells
Authors: Strubhar Malcolm K. , Fitch John L. , Uhri Duane C.
Published: December 2007

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

A procedure is outlined for calculating the performance of a vertically fractured gas well contained within a square drainage area. Constant production rate and the constant well pressure cases are included. Because it is not pressure cases are included. Because it is not a numerical simulator, calculations can be performed practically on small computers. performed practically on small computers. Predicted comparisons with published reservoir Predicted comparisons with published reservoir simulator results and with actual production data from two massive hydraulically fractured wells were made. Agreement in both comparisons was very good.

Introduction

In recent years the concept of massive hydraulic fracturing (MHF) has been developed with particular interest in its application to gas recovery from very low permeability reservoirs. While several factors determine the profitability of applying this technology, one of the most important is the gas recovery rate. Adequate predictions of productivity behavior are imperative for proper economic evaluation. As has been illustrated by Morse and Von Gonten, transient flow effects exist for long periods of time (many years) in these low-permeability reservoirs. Therefore, productivity behavior during this transient productivity behavior during this transient period must be properly assessed in order to period must be properly assessed in order to perform meaningful evaluations. perform meaningful evaluations. Our own interests in MHF technology began several years ago as an integral part of studies considering multiple vertical fractures. At that time, there were no productivity prediction techniques available productivity prediction techniques available that would cover the spectrum of conditions of interest. The work of McGuire and Sikora adequately predicts, for the semisteady-state period, productivity improvements resulting period, productivity improvements resulting from vertical fractures in a bounded reservoir. Prats et al. expressed vertical fracture Prats et al. expressed vertical fracture performance in terms of an effective well performance in terms of an effective well radius. This concept predicts that, for infinitely conductive fractures of up to 50-percent penetration to a circular drainage boundary, there is a hypothetical well radius that would result in the same well performance as the fracture. This effective well radius is approximately equal to one-half the fracture penetration. This idea was shown to apply at penetration. This idea was shown to apply at all times except the very early transient period. The method reported here was developed period. The method reported here was developed to apply to fractures of any penetration with the ability to predict production rate for any time.
Developments in PhosphonoMethylated PolyAmine (PMPA) Scale Inhibitor Chemistry for Severe BaSO4 Scaling Conditions
Authors: Singleton M. A. , Collins J. A. , Poynton N. , Formston H. J.
Published: December 2007

This paper describes the development of a PMPA scale inhibitor chemistry, for potential ‘squeeze’ application, to provide scale inhibition under severe Barium Sulphate scaling conditions. Phosphonate type inhibitor chemistries have been applied in ‘squeeze’ treatments as they have the desired adsorption characteristics to protect the near wellbore formation, perforations and production strings for a significant period of time (known as the ‘Squeeze’ Life). These chemistry types, however, are not the most efficient means of preventing scale deposition in some severe, low pH BaSO4 scaling situations. Polymeric inhibitor species, in particular PolyVinylSulphonates (PVS) and sulphonated co-polymers (VS-Co), are sometimes more suited to these types of conditions, but they do not typically posses the necessary retention characteristics to achieve the desired ‘squeeze’ lifetimes. This paper discusses the development of a new experimental PMPA chemistry which has demonstrated improved inhibition performance under harsh BaSO4 conditions, whilst retaining the adsorption and retention characteristics of earlier PMPA chemistries and could potentially result in considerably longer ‘squeeze’ lifetimes than those currently achieved with the polymeric inhibitors.
Squeezing Aqueous Based Scale Inhibitors into a Water Sensitive Reservoir - Development of a Squeeze Strategy
Authors: Poynton N. , Tidswell R. , Steele J. , Wood Jonathan , Early R.
Published: December 2007

The squeezing of scale inhibitors into the near well bore region of oil producing wells is a recognised solution to downhole scale prevention. In many cases, this downhole application leads to an initial decrease in the well productivity, which can recover to the pre squeeze level with time. However, in some reservoirs this recovery does not happen, and the well suffers a permanent loss in productivity after the squeeze.

Following such a loss in well productivity caused by an initial squeeze treatment, this paper details the development of a successful squeeze treatment for a water sensitive reservoir in the North Sea using an aqueous based sulphonated co-polymer scale inhibitor.

The paper summarises the additional core plug testing undertaken to evaluate the damage mechanism, the modifications made to the treatment design to minimise the damaging effects and culminates with the successful results from the application of the modified squeeze treatment. These results show that well stimulation and extended squeeze lifetime were achieved compared to the initial squeeze and to other previous applications of this inhibitor in similar water sensitive reservoirs.
Eliminating the Need for Scale Inhibition Treatments for Elf Exploration Angola's Girassol Field
Authors: Vu Van Khoi , Hurtevent Christian , Davis Roy A.
Published: December 2007

In the development of Elf Exploration Angola’s Girassol field located approximately 200 km west of the coast of Angola in 1,500 m of water depth, 390,000 barrel per day of seawater will be needed for a waterflood operation. Formation water analysis indicate both barium and strontium levels of approximately 230 mg/l. By the injection of normal seawater containing 2,800 mg/l sulphate, scale tendency calculations indicate the possible formation of more than 320g barium sulphate per m3 of coproduced water. Conventional scale inhibitor squeeze treatments were not considered to be a reliable and cost effective scale control technique due to: 1) Girassol’s "daisy chain" concept with network of wells producing in the same gathering line and subsequent difficulties in monitoring residual inhibitor levels, 2) difficulties in the placement of inhibitors in the reservoir which has high permeability and long perforation intervals, and 3) the deep and remote subsea wells. The high risks using scale inhibition for such a large scale waterflood project in a deepwater environment were considered unacceptable. After the extensive screening of all possible technical alternatives, Elf chose to remove the sulphate from the seawater using a selective nanofiltration membrane process previously used in the North Sea1,2. However, unlike the North Sea operations where scale inhibitors were originally used in combination with low sulphate seawater, Elf chose a specifically designed sulphate removal process with stringent high performance requirements that allows for the initial injection of seawater with approximately 20 mg/l sulphate for the leading edge of the waterflood. This will be followed by low sulphate seawater with approximately 40 mg/l sulphate. Based on 1) the initial low sulphate level in the injection water, 2) the projected scaling kinetics, and 3) the partial precipitation of barium and sulphate in the reservoir before the seawater approaches the production bore, the calculated scale potential is essentially eliminated.
An Improved Method for Analyzing Complex Declines of Wells Completed in Compartmentalized Meander-Belt Systems
Authors: Branagan P. T. , Brown T. D. , Prouty J. L.
Published: December 2007

Effective production-decline analysis is crucial to the successful management of declining oil and gas wells. From analysis of declines caused by reservoir conditions, engineers can generate valuable information such as reserve estimates (useful for property value appraisal) and production forecasts (useful for generating cash-flow forecasts). In short, a production-decline analysis is at the heart of many economic decisions about the future of a well or property.

Because decline analysis is so important, engineers are faced with a significant problem when the conventional methods of analysis break down. For example, wells completed in fluvial, meander-belt systems such as those found in the Piceance basin, Colorado often do not follow the conventional production decline patterns established with exponential and hyperbolic equations. Rather, the decline reflects the complex interaction arising from compartmentalized, point-bar reservoirs that are commingled at the wellbore. This paper presents an improved method of analyzing these complex declines using a numerical simulator.

Central to this method is the definition of six different reservoir types, each of which can be subjected to different boundary conditions and hydraulic fracture options (i.e., with or without fracture, different fracture orientations, different fracture lengths, etc.). While there are other configurations available in nature, these reservoir types form a sufficient representation for modeling purposes of the compartmentalized reservoirs likely to be encountered and produced.

The modeling itself is done in two steps. The first step is to model the individual responses of the reservoir types and superpose the responses in various combinations until a rough match of actual production history is achieved. This best-match combination is then used as a starting point for the second step: modeling the complete system allowing commingling at the wellbore. Further model runs are made until an acceptable match is found. This match is the basis for predicting future performance.
Producing Characteristics and Drainage Volume of Dakota Reservoirs, San Juan Basin, New Mexico
Authors: Sunde Arild , Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

Approximately 500 wells from the low-permeability, tight-gas Dakota formation in San Juan Basin, New Mexico, were analyzed to characterize the producing/flow characteristics, to delineate the drainage volume/area, and to infer the infill potential. Production data is from both commercial and public database. Decline-curve analysis is the primary method. Results indicate that Dakota wells started producing after seventies generally have very steep decline during transient flow period. This is due to the negative-skin effect resulted from well stimulation. During boundary-affected flow period, the production decline tends to be exponential-decline-like (low decline exponent). Estimated gas permeability is in the order of 0.01 md. Drainage pore-volumes of the wells started producing during early eighties are slightly smaller but more uniformly distributed than the wells started producing during sixties and seventies. Drainage areas, however, appear to be less dependent on the date of production than the pore-volumes. Productivity index is highly variable over both basin and time, suggesting a highly heterogeneous flow/permeability field in the Dakota reservoirs.