bluuebunny/crossref_metadata_2025 huggingface dataset:
Deformation of Chalk Under Confining Pressure and Pore Pressure
Authors: Blanton Thomas Lindsay
Published: December 2007

Compression tests with and without pore pressure have been run on Danian and Austin chalks. The rocks yielded under increasing hydrostatic stress by pore collapse. The same effect was produced by holding a constant hydrostatic stress and reducing the pore pressure. This pore collapse reduced the permeability. The ultimate strength of the chalks increased with increasing confining pressure. The yield strength increased initially, but at higher confining pressures it decreased until it yielded under hydrostatic stress. Relatively high pore-pressure gradients developed when the chalks were compressed. In these situations, the mechanical behavior tended to be a function of the average effective stresses.
Motion and Load Prediction of Floating Pipelaying Equipment
Authors: Minkenberg H.L. , Gie Tan Seng
Published: December 2007

In predicting the motions and loads of floating pipelaying equipment - varying from conventional barges to large, highly sophisticated semisubmersibles - several mathematical methods and model experimental techniques are available. This paper reviews the various mathematical methods and correlates the results with model test and prototype data.

Introduction

The concept of a floating barge being a stable floating unit for carrying pipelaying equipment offshore was introduced in 1956. In 1978, the first offshore pipelaying barge, the L.E. Minor, was operated. The pipeline was lowered from the barge to the seafloor using long submerged floating units. By controlling the buoyancy of these units, the required sloping launchway was obtained. Tension was applied only to prevent slipping of the pipeline. The length of such stingers was two to three times the water depth. Stingers up to about 1,000 ft long with a weight up to 250 tons were used. In deeper water and less-sheltered areas, however, stingers of such length and weight became a real problem, especially because of the very large moments generated about the attachment point to the barge. By the introduction of the curves stinger in combination with large axial tensions applied to the pipeline on the barge, the sagbend could be limited so that laying in greater water depth became possible. Allowing a stress level of about 80% of the yielded stress during the laying operations resulted in considerably shorter stingers. Hence, the very large moments about the attachment point to the barge were reduced, which made work in rougher sea conditions possible. Generally, however, the laying techniques themselves hardly changed.

The hull configuration of the unit supporting the pipelaying equipment has varied considerably during the last 10 years. Ship-shaped vessels, small semisubmersibles, and large semisubmersibles with sophisticated pipelaying-controlling systems were developed and taken into operation, in addition to conventional flat-bottom barges. The choice of the type of construction is determined mainly by the following parameters1–3:operational area (worldwide or some specific area - e.g., North Sea, Gulf of Mexico),water depth,size of pipelines (storage capacity, deck area),seabed condition,sea surface condition (workable days, survival capability, stability), andinvestment.

Due to high development and operating costs of pipelaying barges, it is important to consider the various possibilities in early stage. Sea surface conditions and, thus, the hydrodynamic aspects of the various concepts play an important role in the selection of the final concept. The waves, wind, and current acting on the floating pipelaying structure determine mainly whether motions and forces become too large so that the laying activities have to be stopped. The rougher the sea conditions in which it is possible to work, the more time will be available for productive pipelaying in a given season.
Semi-Analytical Well Model of Horizontal Wells With Multiple Hydraulic Fractures
Authors: Wan J. , Aziz K.
Published: December 2007

A well model is required to relate the well rate to the well pressure and the wellblock pressure while modeling wells in reservoir simulators. The well index is calculated automatically by simulators for conventional wells, but it is generally calculated by the user and supplied in the input while modeling nonconventional wells when the default procedure available in commercial simulators is not adequate.

In this paper we describe a new semi-analytical solution for horizontal wells with multiple fractures. The fractures can be rotated at any horizontal angle to the well, and they need not fully penetrate the formation in the vertical direction. This solution for hydraulically fractured wells is obtained by applying Fourier analysis to a 2D solution; therefore, this solution is easy to obtain when the 2D solution is available. The analytical solution provides the well pressure that can be combined with a numerically computed gridblock pressure to obtain the well index (WI). Results of our rigorous solution are compared with empirical approaches currently in use for calculating the well index and the productivity index. Examples are given when horizontal wells with fractures are modeled using our new approach and conventional methods. These results demonstrate the need for computing the correct WI.
A Study of the Orifice Well Tester and Critical Flow Prover
Authors: Lesem Louis B. , McKetta John J. , Fancher George H.
Published: December 2007

Introduction

The proration of oil produced in the field frequently is based partially or entirely upon the gas-oil ratio of wells. The measurement of the gas-oil ratio is one of the more important field tests in regulatory and proration work, and the test always should be conducted according to standardized methods and procedure.

Obviously, the gas-oil ratio and the volume of gas produced by a well depend upon many factors but should be independent of the method of measurement and of the devices used to measure gas and oil. Consequently, the volume of gas accompanying a barrel of oil produced by a well may be measured by any reliable and accurate device or instrument. Frequently either a critical flow prover or an orifice well tester is used for this purpose, and for a particular well the same rate of flow of gas should be obtained regardless of whether a critical flow prover or an orifice well tester is employed in the test.

In Texas, when using either instrument, either Capacity Table 1 or 5 is employed in making the necessary computations. If the tables are used, a discrepancy always is found whenever the two instruments are compared by extrapolation to the same conditions of flow. Clearly, Tables 1 and 5 must be at fault in some respects.

The orifice well tester and the Bureau of Mines type of critical flow prover are essentially the same instrument; both devices utilize a square-edged orifice 1/8 in. in diameter as the primary element, and both freely discharge gas to the atmosphere.

Tables for the orifice well tester have been published in the ranges of 0 to 15 in. of water and 0 to 40 in. of mercury (Hg) differential in pressure. Coefficients for the critical flow prover have been published for differentials in pressure greater than 75 psia.
Pressure Buildup Analysis With Wellbore Phase Redistribution
Authors: Fair Walter B.
Published: December 2007

This paper presents an analysis of the effects of wellbore phase redistribution on pressure buildup tests. Wellbore phase redistribution is shown to be a wellbore storage effect and is incorporated mathematically into a new solution of the diffusivity equation. Dimensionless pressure solutions based on an infinite radial reservoir are presented for type-curve matching to analyze pressure buildup tests influenced by wellbore phase redistribution, and example analyses of actual field data are included. The parameters that affect phase redistribution and gas humping are documented also. This information permits analysis of many anomalous pressure buildup tests which previously could not be analyzed quantitatively.
One-Step Furfuryl Alcohol Process for Formation Plugging
Authors: Hess Patrick H.
Published: December 2007

A one-step furfuryl alcohol resin process has been developed for selective plugging in injection and production wells. Of 36 economic small-volume applications, 28 were successful in achieving permanent plugging. The process is especially useful in steam injection wells. The "chemical clock" catalyst system ensures a controllable, predictable gel time over a wide range of formation temperatures.

Introduction

Furfuryl alcohol (FA) resins are proving to be most useful in oilfield operations. When acidified, these liquids undergo rapid polymerizations to form hard, black, chemically resistant, thermally stable, thermosetting polymers. These polymers are the basis of previously described two-step sand consolidation, and formation plugging processes where either the FA or acid catalyst is placed in the formation first, followed by the other chemical; the chemicals mix, and the polymerization takes place. Generally, two steps with an intermediate spacer have been necessary because the solution rapidly solidifies when the FA and acid mix, whether in the formation, tubing, or pump.

This paper describes a one-step FA process that overcomes the usual problems encountered with a two-step process. This process uses an FA system where, before pumping, the FA and catalyst are mixed to form a solution with a predictable minimum gel time (gel time is the time from mixing until the viscosity has built to the point where the fluid is no longer readily pumpable). Once the gel time is exceeded, the polymerization proceeds rapidly to the fully cured FA (furan) polymer.

Acidic Catalysts

There are three major obstacles to achieving predictable, reproducible FA gel times by adding acidic catalysts directly to the resin:sensitivities to catalyst concentration,reaction temperature, andFA batch history.

The first two problems are illustrated in Fig. 1. Gel times for most polymerizing systems generally decrease with increasing catalyst concentration. This effect is quite pronounced in FA systems. To achieve predictable gel times with acidic catalysts requires accurate measurement of chemical volumes and rapid mixing, difficult requirements under field conditions. Also, to have a reasonable working life, the acid concentration must be so low that a "catalyst-starved" FA system can exist. The resulting polymerization may be benign and occur over a prolonged time span (and quite possibly never reach a high degree of cure). It is more desirable that once the polymerization starts it goes rapidly, with a high exotherm, to the final fully cured state.The temperature effect illustrated in Fig. 1 shows that FA polymerizations, as most chemical reactions, go faster with increasing temperatures. A 2-hour gel time for a given catalyst concentration at room temperature may only be 20 minutes at 140 degrees F (60 degrees C).FA batch history is the third problem. Freshly distilled FA is neutral, but with time and oxygen some of the FA will oxidize to complex acids and lower the pH.

JPT

P. 1834＾
Explosive Fracture Studies on Oil Shale
Authors: Grady Dennis E. , Kipp Marlin E. , Smith Carl S.
Published: December 2007

Fracture, fragmentation, and/or enhanced permeability through explosive methods can be difficult to achieve in the often restricted environment demanded of in-situ resource recovery methods. Blasting within confined volumes and the need for uniform fragment size and permeability adds a dimension for which a history of blasting experience is not available. Computer modeling offers a potential tool for rapid evaluation and optimization of the explosive and geometry parameters. This study deals with intermediate-scale explosive blasting tests within confined volumes that have been conducted on blocks of oil shale to evaluate a computational fracture model under realistic loading conditions. The blocks were instrumented with stress gauges in the material to determine the dynamic stress field induced by the explosion. The blocks were recovered, stabilized, and sectioned after testing to measure the extent of damage and fragment-size distribution. Both stress-wave and fragment-size data were compared with numerical computations.
Shear Wave Velocities Determined From Long- and Short-Spaced Borehole Acoustic Devices
Authors: Koerperich E. A.
Published: December 2007

Acoustic waveforms from long- and short-spaced sonic logs were investigated to determine if shortspaced tools give accurate measurements of shear wave velocity. Compressional wave interference can affect shear velocities from both tools adversely. However, the short-spaced tool was useful over a wider range of conditions.
Case History of Successfully Water Flooding a Fractured Sandstone
Authors: Rausch R.W. , Beaver K.W.
Published: December 2007

By 1955, the First Wall Creek reservoir had reached the stripper stage. At that time a 20-acre double five-spot pilot was started to evaluate waterflood feasibility. Injected water was lost from the pilot area through natural fractures, and the five-spots were not encouraging. However, wells outside the five-spots showed production increases, so the pilot area was expanded to include about 100 acres. The expansion proved highly successful, and a full-scale program is now underway. Sand-oil fracture treatments have contributed to the success of the project.

Introduction

The geology and history of the Salt Creek field, Salt Creek, Wyo., have been described previously. The First Wall Creek pool under consideration here was discovered in 1908 and is one of 11 productive zones found on the Salt Creek anticline. The pool is cut by numerous normal faults of small displacement. Fig. 1 is a field map. Many of the smaller faults have been omitted in this figure. There are surface indications which suggest that some of these faults may be sealed by secondary deposits of calcite. The First Wall Creek pay zone, found at an average depth of 900 ft, is a fine- to medium-grained sand with numerous thin shale partings. Porosity and permeability are locally erratic, and average 15 per cent and 80 md, respectively. Gross thickness of the section averages 120 ft, of which about two-thirds is net pay and the remainder is shale. Core analyses indicate local zones of high permeability, usually near the base of the section. Injectivity profiles from spinner surveys show that extensive natural fracturing is present in some areas, and as a result, matrix permeability does not necessarily determine points of fluid entry into the wellbore. The produced crude is paraffin base, 38 gravity, having an estimated original solution GOR of 550 cu ft/bbl. The northern two-thirds of the Salt Creek field, including all of the First Wall Creek pool, was unitized in 1939, with the Midwest Oil Corp. as unit operator. Pan American Petroleum Corp. conducts the field operations for the unit owners on a contract basis. Sixty-eight companies and individuals are working interest owners in the unit.

Gas Injection

A gas-drive project was started in the Second Wall Creek pool, Salt Creek's largest reservoir, in 1926. This project was successfulit is still in operationso a similar program was attempted in the First Wall Creek starting in 1927. Maximum available surface injection pressure was only 350 psi, and most of the First Wall Creek wells would not take gas at economically significant rates with this injection pressure, so no measurable production benefit was obtained. Injections were nonetheless continued until 1949 to avoid flaring gas. A total of about 2 billion cu ft was injected in 22 years.

JPT

P. 1233ˆ
A Conjugate Gradient-Truncated Direct Method for the Iterative Solution of the Reservoir Simulation Pressure Equation
Authors: Watts James W.
Published: December 2007

This paper describes a way of solving the reservoir simulation pressure equation using preconditioned conjugate gradients. The preconditioning is based on an approximate inverse using a diagonal ordering of the difference equations.

The new method has been tested and compared with the strongly implicit procedure (SIP) on a number of problems in both two and three dimensions. In two dimensions, it is generally faster than SIP; in three dimensions, it is much slower than SIP when SIP works well but can be many times faster than SIP when SIP works poorly.

Use of the new method generally does not require the selection of an iteration parameter, which is a significant advantage over SIP. Furthermore, it is much more reliable than SIP. In other words, it is far less likely to be unable to solve a given problem than SIP is.
Contact Angles for Equilibrated Microemulsion Systems
Authors: Reed Ronald L. , Healy Robert N.
Published: December 2007

Advanced and receded contact angles have been measured on various high- and low-energy substrates as functions of microemulsion-excess phase interfacial tensions (IFT’s). Many experimental difficulties peculiar to these low-tension systems caused large measurement errors. But with this constraint and with one exception, contact angles were hysteresis-free and independent of the substrate.

For lower-phase microemulsions and high-energy substrates, it is proposed that the surfactant polar group adsorbs on the solid and then a surfactant bilayer forms. This bilayer provides the effective substrate that relates to contact angle and IFT’s through Young’s equation.

An optimal salinity for contact angles is defined and related to previously introduced optimal salinities, in particular to that associated with best oil recovery. Results suggest the optimum attainable contact angles for microemulsion-based oil recovery may not be 0°.
Stratification Testing Results in Revised Concept of Reservoir Drive Mechanism, University Block 13 Ellenburger Field
Authors: Ader Joseph C.
Published: December 2007

Stratification testing in late 1977 proved that water coning is not operative through the Middle Ellenburger zone in the University Block 13 Ellenburger field in Andrews County, TX. The ensuing deepening and development drilling program has proved the existence of deeper reserves and has revised the plan of depletion for this field.

Introduction

The Ellenburger horizon in west Texas was deposited in a shallow marine environment nearly 500 million years ago during the early Ordovician period. The end of the Ellenburger deposition was marked by folding, faulting, and erosional activity. Extensive geological analysis of cores, drill cuttings, logs, and insoluble residue analysis data has shown that the Ellenburger may be divided into distinct upper, middle, and lower zones. Historically, most Ellenburger reservoirs were assumed to have an active bottomwater-drive producing mechanism, with vertical fractures through the thick carbonate being responsible for the vertical fluid movement. Consequently, numerous Ellenburger reservoirs were developed with a majority of the wells completed at or very near the top of the formation to prolong water-free production and minimize the water coning problem associated with an active bottomwater-drive mechanism.Since its discovery in 1960, the University Block 13 Ellenburger field, a west Texas carbonate reservoir found at a depth of approximately 11,000 ft (3353 m), was considered to have a bottomwater-drive mechanism; consequently, completions had been made only in the top of the Upper Ellenburger to minimize water coning as long as possible and to maximize recovery. When the four upstructure Ellenburger wells began producing water in 1977, approximately 8 years earlier than predicted by previous flood-out analysis, a testing program was initiated to determine whether aggravated coning through 140 to 240 ft (43 to 73 m) of oil column or edgewater encroachment through the Upper Ellenburger was responsible for early water production.Special testing, workover, and development drilling activity has resulted in a revised concept of the reservoir drive mechanism in this field. Stratification testing in late 1977 proved that water coning is not operative through the Middle Ellenburger in this reservoir and that the Ellenburger may be divided into upper, middle, and lower zones with restricted vertical communication between zones. To date, four of six deepenings and two development wells have been completed successfully at or near field top allowable of 285 BOPD (45 m3/d oil) per well in the Middle or Lower Ellenburger zones to recover reserves that may have been trapped under former completion practices.Various techniques have been used to evaluate zonation of the Ellenburger in this field. These geological techniques, along with various reservoir analyses, may aid in identifying potential deep zone reserves in other west Texas Ellenburger reservoirs.

JPT

P. 1452
Improved Reservoir CharacterizationA Key to Future Reservoir Management for the West Seminole San Andres Unit
Authors: Harpole Kenneth J.
Published: December 2007

A comprehensive reservoir study using a black-oil simulation model showedthat control of vertical movement of oil into the gas cap under waterfloodoperations was the key to maximizing oil recovery from this west TexasSan Andres reservoir. Recovery of an additional 4 MMSTB of oil isexpected as a result of a reservoir management plan which includes a46-well infill drilling program.

Introduction

Improved reservoir description is becomingrecognized as an essential requirement for effectivereservoir management. This is particularly important for the extremely heterogeneous, geologicallycomplex San Andres carbonate reservoirs of westTexas. The West Seminole field in west centralGaines County, TX, (Fig. 1) produces from the SanAndres formation at an average depth ofapproximately 5,100 ft. Fig. 2a shows the generalstructural configuration of the reservoir; it consistsof a large main dome with a smaller dome structureto the east. A large primary gas cap, shownschematically in Fig. 2b, covers most of the fieldarea. A summary of basic reservoir and fluid data ispresented in Table 1.

Throughout the field's producing life, there hasbeen a question about the extent of verticalcommunication within the reservoir, particularly betweenthe oil zone and the overlying gas cap. This questionbecame a critical operating consideration when apattern waterflood was proposed in the early 1970's.An extensive reservoir study was undertaken topredict the future production performance of thefield under waterflood operations.

The overall objective of this study was to developthe most profitable and effective reservoir managementprogram for the West Seminole San Andres Unit. Thefollowing specific objectives and procedures weredeveloped for the work.Use all available geologic and engineering datato develop a detailed and accurate reservoirdescription for this field.Incorporate the reservoir descriptioninformation into a black-oil computer simulationmodel. Use the simulator to verify and further refine the reservoir description by history matching thepressure and production data.Use the history-matched simulation model toproject future reservoir performance under currentwaterflood operations.Evaluate various alternative operating plans andrecommend the most effective reservoir managementprogram for the unit.

JPT

P. 2009＾
A Robust Iterative Method for Flash Calculations Using the Soave-Redlich-Kwong or the Peng-Robinson Equation of State
Authors: Nghiem L. X. , Aziz K. , Li Y. K.
Published: December 2007

A robust algorithm for flash calculations that uses an equation of state (EOS) is presented. It first uses a special version of the successive substitution (SS) method and switches to Powell's method if poor convergence is observed. Criteria are established for an efficient switch from one method to the other. Experience shows that this method converges near the critical point and also detects the single-phase region without computing the saturation pressure. The Soave-Redlich-Kwong1 (SRK) and the Peng-Robinson2 (PR) EOS's are used in this work, but the method is general and applies to any EOS.
SACROC Unit Operations
Authors: Allen H.H. , LaRue C.R.
Published: December 2007

A comprehensive and exhaustive study was made by engineering representatives of many owner companies and consultants between the discovery of the Kelly-Snyder field in Nov., 1948 and March 1, 1953, the effective date of SACROC Unit. Since that date the operating personnel have placed in operation a pressure maintenance program consisting of two component parts:water injection into wells located generally along the longitudinal axis of the field andless efficient edge wells shut-in with allowables transferred to more efficient wells in the center of the field.

The performance of the reservoir under pressure maintenance has been closely studied and analyzed. Practical evaluations have been made, and operations continued or modified as conditions required. Results have been most gratifying, and based upon that experience and performance, future operations and planning can be determined with a much greater degree of certainty than when the project started.

This paper will present the pertinent fact relating to pressure maintenance operation of the Kelly-Snyder field by SACROC Unit since the actual beginning of pressure maintenance in 1954 up to the present time.

Introduction

It is one thing to discover an oil reservoir of 2,800 million STB of oil but quite another thing to produce it. Thus, in the case of Kelly-Snyder field, Scurry County, Tex., early performance indicated a primary recovery of only 670 million bbl, and that 2,130 million bbl would not be recovered if primary methods only were used. Hence, the creation of SACROC Unit and the pressure maintenance program. Despite the fact that the organizational set-up of SACROC Unit is most complex and little understood, except by those involved with over-all operations, no time or space will be taken to discuss that subject because it is outlined in the SACROC Unit Agreement.

SACROC Pressure Maintenance Plan

Early in the life of Kelly-Snyder field, it was apparent that a solution gas drive was the only natural production mechanism because presence of water along the southeast flank of the field proved to be only a water drive of insufficient magnitude to be considered a recovery mechanism.
Directional Drilling - A Comparison of Measured and Predicted Changes in Hole Angle
Authors: Sutko Adolph A. , Myers George M. , Gaston Jonathan D.
Published: December 2007

This paper compares measured hole angle changes and predicted angles between bit force and hole direction. The predictions were made using an analytical program that assumes the drillstring is a static beam with varying properties constrained by borehole geometry. Data were taken from a field study conducted in Dubai. Agreement was good for 8 of 12 cases and improved with use of an interpretive length.

Introduction

Directional drilling continues to play an important part in offshore field development. A more thorough and firmly based understanding of the factors affecting hole angle and direction are needed so that drilling can be done as economically as possible and so that overall drilling technology can advance at a uniform rate.Probably the most concentrated recent effort toward a logical and thorough understanding of the factors involved in directional drilling is that of Millheim. Among his works are a series of articles dealing with proper use of directional tools, bottomhole assembly (BHA) mechanics, and behavior of single- and multiple-stabilizer BHA's. In the first of these articles, he lists 46 references but states that there is still much to learn. Later in the series, he presents material derived from postanalysis of more than 70 wells in the U.S. and overseas, field tests, computer analyses, literature, and research.In other articles, Millheim et al. describe a finite-element method of analyzing BHA's and Millheim discusses hole curvature as it relates to hole trajectory. Among the conclusions reached are that reaction forces at the bit can be calculated, the dropping or building tendencies of various assemblies can be assessed, and hole curvature can play a significant role in deviation and deviation control. Walker and Friedman present a three-dimensional force and deflection analysis of a drillstring and state that the use of the model can improve the understanding of how various assemblies compare and can assist in determining the direction the bit will drill. Fischer describes an analysis of a drillstring in a curved borehole and concludes that valuable insight into the mechanical performance of drillstrings can be gained using such an analysis. In discussing the factors that affect the control of borehole angle in straight and directional wells, Bradley gives information relating to the location of drillstring tangency, drill collar stiffness and weight, placement of stabilizers, and downhole motor case flexibility. He emphasizes the need for additional research into the bit/rock interaction as it affects the deviation process.Analytical programs like those in Refs. 1 through 6 calculate the force acting at the bit. Although it generally is agreed that the bit tends to drill in the direction of this force, Millheim and Warren indicate that no method is available to predict rates of build, drop, or turn for a particular set of conditions.

JPT

P. 2090＾
Use of a Well Model To Determine Permeability Layering From Selective Well Tests
Authors: McGee Paul R.
Published: December 2007

This paper describes the use of a numerical well model to determine permeability layering from selective drillstem and production tests for two wells in two Middle East reservoirs. Permeabilities of various geologic layers of a stratified reservoir may be determined by careful planning of selective drillstem tests coupled with a well model to interpret the pressure behavior of each test.

Introduction

The Middle East Reservoir A is a complex carbonate reservoir exhibiting considerable lateral and vertical lithological changes with consequent variation in reservoir characteristics. Based on three previous wells, six geologic units were identified, only five of which are considered productive. Drilling of Well 4 was planned to include drillstem tests of each of these five geologic units to determine their flow characteristics. After the well was completed, it was perforated and acidized and long-term production tests were performed. A numerical well model was developed for use in interpreting these tests by matching pressure buildup performance. This numerical model incorporated all the known geological zonation based on geologic analysis of the four wells drilled to that time. A three-dimensional well simulator was used in this modeling. However, it was used in a two-dimensional radial mode.Later this same technique was applied to an infill well in Middle East Reservoir B. This reservoir has been producing for several years. It is a carbonate reservoir and has considerable variation in lithological characteristics in both the lateral and vertical direction. Selective drillstem tests were conducted on Well 149 at the time it was drilled.

Well 4 Drillstem Tests

A schematic of the drillstem test procedure is shown in Fig. 1. After each geologic unit was drilled, a packer was set isolating that unit while a drillstem test was conducted. The well was produced for time periods ranging from 4.4 to 7 hours with two pressure recorders opposite the producing intervals. The well then was closed, and the buildup pressures were recorded.Reservoir A is highly undersaturated such that single-phase oil flow occurred at all times in all tests. While the reservoir has an aquifer, the well is located on the crest of the reservoir a considerable distance away from the water zone. Cores were obtained from all geologic units for Well 4.A radial well model was constructed to simulate the performance of this well. To have the first grid point as close to the wellbore as possible, it was selected 1 ft (0.30 m) from the wellbore. Six additional radial segments increase logarithmically in size to encompass a total drainage radius of 4,000 ft (1219.2 m). This radius is roughly comparable to the distance from the well to the leading edge of the oil/water contact. A constant-pressure outer boundary was assumed. However, for the short-term drillstem tests, it did not matter whether the outer boundary was sealed or at constant pressure due to the short duration of the tests.

JPT

P. 2023＾
Underbalanced Drilling Dynamics: Two-Phase Flow Modeling and Experiments
Authors: Lage Antonio C. V. M. , Fjelde Kjell K. , Time Rune W.
Published: December 2007

A dynamic model based on the drift-flux formulation is presented for treating transient phenomena in underbalanced drilling (UBD) operations. A set of mechanistic steady-state procedures for dealing with the definition of flow patterns, pressure drops, gas volumetric fractions, and in-situ velocities completes the model. The iteration between those mechanistic laws and the conservation equations is discussed. The numerical solution uses a composite explicit scheme, which reduces false oscillations and numerical diffusion. In addition, details about the boundary treatment are also presented.

Model predictions are validated through comparison to fullscale experimental data in two distinct transient situations: first, a typical liquid unloading, and second, the injection of a high-velocity single pulse and a sequence of two pulses of a gas/liquid mixture. The comparisons address model limitations and improve the understanding of the physics involved.
Multilateral Pressure-Transient Response
Authors: Yildiz Turhan
Published: December 2007

This study presents a 3D analytical model to analyze the transient flow into multilateral horizontal wells. The model considers arbitrary phasing angle, selective lateral completion, nonuniform formation damage around each lateral, and areal and vertical permeability anisotropy. Using the model, transient pressure, derivative, and rate distribution characteristics of multilateral horizontal wells are investigated. Flow regimes are examined. Asymptotic approximations for each flow regime and pseudoskin equation are provided.

A sensitivity study is carried out to identify the parameters controlling the transient pressure, derivative, and fractional rate responses. The sensitivity study includes the impact of lateral length, orientation, and number, formation anisotropy, and the degree of formation damage around the laterals. If all the laterals are put on production during the test, it is almost impossible to estimate principal permeabilities, their directions, and skin factors around each lateral by examining transient pressure and derivative responses only. When all the branches produce, the transient rate distribution is strongly controlled by the skin owing to formation damage. Therefore, if transient rate distribution data, as well as the pressure, is recorded during the test, nonuniqueness in the interpretation of test data may be minimized. Although it is more expensive and time-consuming, testing each lateral individually may provide more reliable estimates of formation properties and damage.
Theory of Multicomponent, Multiphase Displacement in Porous Media
Authors: Helfferich Friedrich G.
Published: December 2007

The basis of a general theory of multicomponent, multiphase displacement in porous media is presented. The theory is applicable to an arbitrary number of phases, an arbitrary number of components partitioning between the phases, and variable initial and injection conditions. Only the effects of propagation are considered; phase equilibria and dependence of fractional flows on phase compositions and saturations are required as input, but any type of equilibrium and flow behavior can be accommodated. The principal simplifying assumptions are the restriction to one dimension, local phase equilibria, volume additivity on partitioning, idealized fluid dynamic behavior, and absence of temperature and pressure effects. The theory is an extension of that of multicomponent chromatography and has taken from it the concept of "coherence" and, for practical application, the tools of composition routes and distance/time diagrams. The application of the theory to a surfactant flood is illustrated in a companion paper.1
Multiwell Variable-Rate Well Test Analysis
Authors: McEdwards Donald G.
Published: December 2007

A computer-based nonlinear least-squares method of pressure matching is presented. The program analyzes for transmissivity, T, storativity, S, and production well skin effect, Δps. It also detects the type (leaky or no-flow) and location (angle and distance) of any vertical hydrologic boundary that may be present. Pressure data affected by several production wells can be treated and, in addition, the variable production-rate history of each production well can be modeled as rigorously as the quality of the production data permit. The technique handles variable flow rates by a linear flow rate solution. Pressure data from several wells may be analyzed simultaneously for reservoir properties. The assumptions concerning the reservoir and well system are those of the conventional analysis methods that employ the line-source solution.

The computer program minimizes the statistic χ2, which is the average of the square of the normalized difference between the calculated pressure change and the observed pressure change:

The normalized pressure difference is used to give equal weight to all pressure responses, regardless of their magnitude. The average of the square of the normalized pressure differences is used so that results from several analyses that differ in their number of observed pressures can be compared.
In-Situ Combustion Model
Authors: Coats Keith H.
Published: December 2007

This paper describes a numerical model for simulating wet or dry, forward or reverse combustion in one, two, or three dimensions. The formulation is considerably more general than any reported to date. The model allows any number and identities of components. Any component may be distributed in any or all of the four phases (water, oil, gas, and solid or coke).

The formulation allows any number of chemical reactions. Any reaction may have any number of reactants, products, and stoichiometry, identified through input data. The energy balance accounts for heat loss and conduction, conversion, and radiation within the reservoir.

The model uses no assumptions regarding degree of oxygen consumption. The oxygen concentration is calculated throughout the reservoir in accordance with the calculated fluid flow pattern and reaction kinetics. The model, therefore, simulates the effects of oxygen bypassing caused by kinetic-limited combustion or conformance factors.

We believe the implicit model formulation results in maximum efficiency (lowest computing cost), and required computing times are reported in the paper.

The paper includes comparisons of model results with reported laboratory adiabatic-tube test results. In addition, the paper includes example field-scale cases, with a sensitivity study showing effects on oil recovery of uncertainties in rock/fluid properties.
Production Technology Experience in a Large Carbonate Waterflood, Denver Unit, Wasson San Andres Field
Authors: Ghauri W.K.
Published: December 2007

Shell Oil Co. currently is operating a large waterflood project in the Permian San Andres dolomite reservoir in west Texas. The project comprises 900 producers and 360 injectors. In addition to major infill drilling programs, a substantial remedial and reconditioning program has been carried out. Highlights of production technology experience are presented.

Introduction

The Denver Unit waterflood project in the Wasson San Andres field in West Texas ranks among the largest supplemental recovery projects currently operating in the U.S. (Fig. 1). Shell Oil Co. is the operator and holds the major working interest. The paper has evolved through several phases of infill development drilling and flood pattern modifications that have been carried out in the course of conducting the waterflood project.

The paper is divided into two parts. The first deals with a brief history of the waterflood with the objective of providing the project setting for the production technology practices currently being followed. The emphasis is placed not on the statistical data per se but rather on the evolutionary process through which present procedures have been developed, as well as their interrelationship with the geologic, petrophysical, and reservoir aspect as as they pertain to the project. The second part describes the specific practices of well completion, well stimulation, injection profile control, artificial lift, flood surveillance, and related drilling, remedial, and reconditioning operations now being used and how they have contributed to the enhancement of ultimate recovery from the project.

Historical Background

The Wasson San Andres field was discovered in 1936. The bulk of primary development at 40-acre (162 000-m2) well spacing was completed by the early 1940's. Supplemental recovery operations were initiated with unitization and commencement of water injection in 1964 (Fig. 2).

The producing horizon is the Permian San Andres dolomite formation at an average depth of 5,200 ft (1585 m). Gross oil pay thickness varies between 200 and 500 ft (60 and 150 m). The structure is an anticline capped by dense dolomite and underlain by an essentially inactive aquifer. Solution-gas drive has been the primary producing mechanism. Table 1 shows a summary of basic project data. The oil reservoir has an original gas cap. Although some production has occurred from the gas cap, primarily before unitization, Shell's policy during waterflooding operations has been to leave the gas cap unexploited to conserve reservoir energy and prevent waste by the migration of oil into the gas cap.

When unitization was effected in 1964, the geologic concept of the reservoir was a simplistic one and was markedly different from the rather complex model that has evolved today. The original definition of the San Andres reservoir was based on gross geologic correlations of reservoir-quality rock and the assumption that this rock largely was interconnected over the entire extent of the unit.
Correlation of Gelation Times for Polymer Solutions Used as Sweep Improvement Agents
Authors: Terry Ronald E. , Huang Chyi-gang , Green Don W. , Michnick Michael J. , Willhite G. Paul
Published: December 2007

Gelled polymers are being used increasingly to redirect or modify reservoir fluid movement in the vicinity of injection or production wells for the purpose of improving water/oil ratios. To date, little has been reported about the chemistry of the in-situ gelling process that involves a multivalent metal ion, a reducing agent, and a polymer. This paper reports results of a study of the relationship between process parameters and gelation time, which is defined as the time required for the solution to reach a specified viscosity. The gelation time is determined by continuous monitoring of the viscosity following addition of the chemical reactants. The varied parameters in the investigation include polymer type and concentration, chromate concentration, and reducing-agent type and concentration. Five different polyacrylamide polymers were used including polyacrylamides that were hydrolyzed to different degrees, an anionic copolymer, and a cationic copolymer. Sodium bisulfite and thiourea were used as reducing agents. It was determined that for a given polymer-reducing agent system, the reciprocal of gelation time is a linear function of the reciprocal of the polymer concentration for a fixed metal ion concentration. The slope of the straight line is a function of the degree of polymer hydrolysis, the existence of the anion or cation functional groups, and type of reducing agent used.
Thermal Stability of Starch- and Carboxymethyl Cellulose-Based Polymers Used in Drilling Fluids
Authors: Thomas David C.
Published: December 2007

Starch- and cellulose-based polymers have been used to control water loss for many years. Thermal degradation of the polymers is the most important problem with their use. Representative starch and cellulose fluid loss reducers were tested for their thermal stability in mud systems. The thermal decomposition was found to be dependent on both exposure time and temperature. The rate of decomposition can be predicted using first-order reaction rate kinetics and the decomposition activation energy estimated for both polymer types. This technique allows the calculation of a polymer's usable lifetime at a given temperature. A table of half-lives (time for fluid loss to double) vs. exposure temperature is presented for both starch- and cellulose-based polymers. This paper discusses the results of the calculations and the method used to obtain the data. The method is generally applicable to any material used in drilling fluids that is subject to thermal degradation.
Adjustment of Differential Liberation Data to Separator Conditions
Authors: Al-Marhoun Muhammad A.
Published: December 2007

Solution gas/oil ratio (GOR) and oil formation volume factor (FVF) are normally obtained from differential or flash liberation tests. However, neither the differential liberation process nor the flash liberation process can represent the fluid flow in petroleum reservoirs. Therefore, data obtained from any of the two test procedures must be adjusted to approximate the fluid behavior in the reservoir. At low pressures, the conventional method of adjustment yields negative values of solution GOR and values of oil FVF of less than 1. This, of course, is not physically correct.

This paper presents a new method for adjusting the differential liberation data to separator conditions. The new method overcomes the limitations of the conventional adjustment method and makes the low-pressure extension of the curves of solution GOR and oil FVF more accurate. The method is based on the fact that data obtained from both the differential and flash liberation tests should yield the same value of oil relative density at reservoir conditions. The new method is tested using 425 PVT files, yielding results that are consistent with the physical behavior of solution GOR and oil FVF.
Structure and Process Optimization for the Use of a Polymeric Relative-Permeability Modifier in Conformance Control
Authors: Eoff Larry , Dalrymple E. Dwyann , Reddy B. R. , Everett Don M.
Published: December 2007

For many years, relative-permeability modifiers (RPMs) have received a great deal of attention from the oil- and gas-production industry. Because of the completion techniques used in many wells, it is not always practical or cost-effective to protect the hydrocarbon interval properly during a water-shutoff treatment. RPMs offer the option of bullheading a treatment without zonal isolation, which is designed to decrease water production with little or no decrease in oil or gas production.

This paper describes the laboratory development and optimization of a polymeric RPM. The resulting material can be best described as a brush polymer consisting of a polymeric backbone grafted with methoxypolyethylene glycol (MPEG). Various phases of the development will be discussed, such as the optimization of the molecular weight of the backbone polymer and the concentration of grafted MPEG. Details of laboratory evaluations will also be provided, including a discussion of the use of multipressure-tap flow cells for permeability-reduction tests, the effect of polymer concentration, and the effect of saturations. These test results show that the RPM polymer should be placed with a systematic approach consisting of proper preflushes and postflushes for optimum results.