bluuebunny/crossref_metadata_2025 huggingface dataset:
The Effect of an Initial Gas Content on Thermal EOR as Applied to Oil Sands (includes associated papers 18399, 18568 and 18743 )
Authors: Frauenfeld T.W.J. , Ridley R.K. , Nguyen D.M.
Published: December 2007

This paper discusses the results of a number of physical model experiments on thermal EOR. Seven experiments were performed, three in which a "dead" heavy oil was used, and four in which the oil sand was saturated with methane. For oils without an initial gas content, coinjection of CO2 with steam was capable of improving oil recovery over that obtained with steam alone. When an initial dissolved gas was present, coinjection of CO2 was not beneficial. Injection of CO2 or CH4 slugs just before steam injection was beneficial in increasing oil recovery for experiments where an initial dissolved gas was present.

Introduction

Numerous researchers have reported results on thermal EOR in heavy oil. These results refer to field experience and to numerical modeling studies. Little experimental work is available on the significance of dissolved gas in thermal recovery processes. This work was done to provide data on the effects of dissolved gas on cyclic steam stimulation. The work consists of seven large physical model experiments with and without an initial dissolved gas content. Meldau et al. reported on a field application of air injection with steam in a reservoir containing 11° API [0.99-g/cm3] oil. They also performed a numerical study that indicated that injecting gas with steam produced substantial improvements in oil production. Their model assumed a dead oil and therefore did not study the effect of an initial gas saturation. They found that the mechanisms responsible for improved oil recovery were trapping of gas below the critical saturation value, increased gas drive of oil near the wellbore, movement of heat into the upper layers of the reservoir, and higher reservoir pressure during drawdowns.

Hong and Ault performed a numerical simulation of a heavy-oil and a light-oil steamflood. They compared steam-only injection to the injection of steam with a noncondensable gas. They assumed a 14° API [0.97-g/cm3] heavy oil in 4,000-md sand and no initial gas saturation in their oil. Coinjection of CO2 or N2 with steam improved the early oil recovery from a steamflood of a heavy-oil reservoir. However, the ultimate oil recovery was the same as that for a steam-only injection. The enhanced early recovery was a result of the sweep of the reservoir by injected gas.
Fluid Flow and Sand Production in Heavy-Oil Reservoirs Under Solution-Gas Drive
Authors: Smith Gerald E.
Published: December 2007

The production of heavy oil in Canada has led to a number of anomalous results, most of which have been excused as high-permeability channels resulting from sand production. The methods of soil mechanics predict gross formation failure resulting from high fluid compressibility, small cohesion, and high viscosity. Gross failure results in excellent productivity but reduced in-situ stress (and fracture stress).

Solution-gas drive in these reservoirs involves simultaneous-mixture flow of gas as very tiny bubbles entrained in heavy oil. Stress, geometry, and permeability alteration resulting from matrix deformation combined with peculiar pressure-dependent multiphase-flow properties result in a new model of reservoir performance. A field observation of stress modification is discussed, as are the contributions of the four components discussed previously to the observed phenomena.
Multiple-Well Interference Testing in the Ohaaki Geothermal Field
Authors: Leaver J. D. , Sageev A. , Ramey H. J.
Published: December 2007

Multiple interference tests were carried out in the Ohaaki geothermal field between 1979 and 1983. Data were collected for periods of up to 200 days per test with both wellhead-mounted water-level recorders and quartz crystal pressure gauges, each with a resolution of about 0.0145 psi [100 Pa], Data are analyzed by conventional log-log type-curve matching techniques, followed by application of recently developed semilog type-curve matching techniques that allow linear boundary detection without developing two semilog straight lines. One type curve exists for each of the drawdown and buildup data, which are produced by mathematically collapsing the family of curves produced in the solution for a system containing a line source and linear boundary. The type curve for die buildup data has not been previously published. The method allows the inference ellipse for a linear boundary to be determined without any knowledge of reservoir parameters.

The data in some tests show the presence of a no-flow boundary for which inference ellipses have been located. Four interference tests performed on the same doublet show that vastly different reservoir parameters can be found unless careful interpretation is made.
Fractured Geothermal Reservoir Growth Induced by Heat Extraction
Authors: Tester J. W. , Murphy H. D. , Grigsby C. O. , Potter R. M. , Robinson B. A.
Published: December 2007

Field testing of a hydraulically stimulated, hot, dry rock (HDR) geothermal system at the Fenton Hill site in northern New Mexico indicated that significant reservoir growth occurred as energy was extracted. Tracer, microseismic, and geochemical measurements provided the primary quantitative evidence for the increases in accessible reservoir volume and fractured rock surface area that were observed during energy extraction operations that caused substantial thermal drawdown in portions of the reservoir. These temporal increases suggest that augmentation of reservoir heat-production capacity in an HDR system may be possible.
Application of the Boundary Integral Method to Immiscible Displacement Problems
Authors: Masukawa Junichi , Horne Roland N.
Published: December 2007

This paper presents an application of the boundary integral method (BIM) to fluid displacement problems to demonstrate its usefulness in reservoir simulation. A method for solving two-dimensional (2D), piston-like displacement for incompressible fluids with good accuracy has been developed. Several typical example problems with repeated five-spot patterns were solved for various mobility ratios. The solutions were compared with the analytical solutions to demonstrate accuracy. Singularity programming was found to be a major advantage in handling flow in the vicinity of wells. The BIM was found to be an excellent way to solve immiscible displacement problems. Unlike analytic methods, it can accommodate complex boundary shapes and does not suffer from numerical dispersion at the front.
Williston Basin: An Analysis of Salt Drilling Techniques for Brine-Based Drilling Fluid Systems
Authors: Stash Sandra M. , Jones Mark E.
Published: December 2007

Williston Basin salt intervals, ranging in depth from 5,000 to 12,500 ft [1525 to 3810 m], have been responsible for widespread casing collapse because of the plastic movement of evaporites and the subsequent point loading of casing. This phenomenon is attributable to poor cement jobs across excessively eroded salt sections. A 2-year study led to the realization that this erosion is a function of not only salt dissolution but also the mechanical action of turbulent flow in the wellbore. A laminar flow regime can be realized and salt enlargement limited by careful control of annular flow rate, jet velocity, and drilling-fluid rheology.
Practical Techniques in Two-Pseudocomponent Black-Oil Simulation
Authors: Shank G. D. , Vestal C. R.
Published: December 2007

An efficient black-oil simulator based on a two-pseudocomponent representation of standard hydrocarbon physical-property data has been developed. This simulator solves the differential equations describing three-phase flow in a porous medium for black-oil, volatile-oil, condensate, and dry-gas systems. The fluid system consists of two-pseudocomponents—separator gas and stock-tank oil—and water. Descriptive equations are obtained by writing molar balances for the water phase, the stock-tank oil component in the hydrocarbon vapor and liquid phases, and an overall balance in the hydrocarbon vapor and liquid phases. The set of equations is solved by use of either a sequential method or a fully implicit method. The mathematical formulation allows rigorous simulation of reservoir problems involving variable bubblepoint or dewpoint pressures. Practical aspects, such as comparing the simulator physical property data to the laboratory PVT tests, performing flash calculations, and calculating phase boundary pressures, are discussed.
LaBarge Project: Availability of CO2 for Tertiary Projects
Authors: Hunter J.K. , Bryan L.A.
Published: December 2007

Exxon Co., USA is constructing a large gas processing facility northeast of Kemmerer on the Lincoln-Sweetwater County line in southwest Wyoming. The plant will process raw gas from three Exxon operated units northwest of LaBarge, in Sublette County.

The LaBarge Field is being developed primarily to recover and sell methane; however, the field is also a significant source of carbon dioxide, sulfur and helium. As a source of CO, the LaBarge Field will provide oil producers in the Rocky Mountain area an opportunity to increase production in their mature fields through EOR projects.

A 649-mile pipeline is planned to transport up to 650 Mcfd of CO, to users throughout Wyoming and Willisiton Basin. Exxon's CO, marketing survey indicates potential CO, demand of 4.4 trillion cubic feet in the planned marketing area for enhanced oil recovery. About 25% of the CO2 demand identified is already contracted. LaBarge CO2 will allow Northern Rocky Mountain 'operators to potentially recover an additional one billion barrels of oil reserves.

Introduction

Exxon's gas plant, scheduled for startup this year, is designed to process 480 million cubic feet per day of raw gas yielding 114 Mcfd ( m = million, G = billion, T = trillion) of methane, and 250 mcfd of CO2. The initial phase of the plant is currently being built and a future expansion is under evaluation. Expansion timing will depend on the economic climate and commitments for plant products. while methane is the primary product being developed in the LaBarge Project, the field will also produce marketable quantities of CO2, sulfer, and helium. The CO2 is being offered for sale to operators in Colorado, Wyoming, North Dakota, Montana, and Canada as an injectant for their EOR projects.

Background

The well field consists of three Exxon operated units covering over 63 square miles (see Fig. 1). These units are located about 10 miles northwest of the town of LaBarge in Sublette County. Exxon owns an average of 95% (Jan.'86, leased committed acreage) of the Lake Ridge, Fogarty Creek, and Graphite Units. Production is from the Madison, a 900 foot thick carbonate reservoir ranging in depth from 14,000 to 18,000 feet. Structurally the Madison Reservoir is located on a large NW-SE trending anticline. The boundaries have not yet been accurately defined but do extend beyond the three Exxon operated units. The National Petroleum Council estimated that the LaBarge-Big Piney area contains 20–25 Tcf of CO2 reserves alone (EOR, p.33, 1984).

P. 249^
A Random-Scission Model for Chemical Degradation of Polymer Solutions
Authors: Khorrami P. , Radke C. J.
Published: December 2007

A rigorous but simple deterministic model is presented to quantify chemical degradation of high-molecular-weight polymer solutions undergoing random bond scission. Molecular-weight alteration is characterized by a fundamental rate constant, k, whose inverse represents the average lifetime of a polymer chain bond. Evaluation of the proposed random-scission model (RSM) against known Monte Carlo (MC) calculations shows complete agreement.

Given the molecular-weight decline from the RSM, we establish the corresponding polymer solution viscosity loss using the semiempirical Martin equation along with the Mark-Houwink relationship for intrinsic viscosity. Comparison of the RSM viscosity predictions against the chemical degradation data of Shupe for partially hydrolyzed Polyacrylamide gives good agreement. Thus, a new tool is available to predict polymer chemical degradation and viscosity loss at reservoir time scales and conditions.
Unique Characteristics of Barium Sulfate Scale Deposition
Authors: Weintritt D.J. , Cowan J.C.
Published: December 2007

Methods of studying oilfield mineral scale deposition in the laboratory do not work for barium sulfate because only small nonadhering crystals are formed. On the other hand, barium sulfate scale found in down-hole or surface equipment is strongly adhering and may contain very large crystals. Results suggest that most of the difference derives from the extremely low solubility of barium sulfate. Firm adherence of scale and the consistent development of oriented crystals 100 microns and larger suggest a relationship between scale adherence and crystal growth. Data from this study indicate some reasons for barium sulfate's occurring as a deposit in oilfield waters. The unique characteristics as well as the associative properties of barium sulfate scale as related to calcium carbonate and calcium sulfate are shown.

Introduction

The first observed deposition of barium sulfate scale in oilfield production equipment is unknown but probably coincides closely with the beginnings of the oil industry itself. Moore described barite oolites in some producing wells in the Saratoga field, Tex., in 1914. Currently, positive identification of barium sulfate deposition is recorded in most of the major oil-producing areas of the United States. As efforts continue to identify the composition and functions of the materials found in scale deposits. the geographic and economic importance of the part played by barium sulfate will become even more important. This belief is based on the following facts.Many oil fields in the U. S. are in or entering their mature phase and the volume of produced water is increasing; thus, the cumulative effects of low-solubility minerals become more significant.Secondary recovery techniques and increased emphasis on waste disposal systems require controlling the behavior of all constituents of water to prevent formation plugging.The more general use of instrumental analysis has reduced the time and improved the accuracy of complete scale and water analysis.Once formed, barium sulfate scale is resistant topresent methods of chemical removal; therefore, costly mechanical methods are necessary.

Thus, new methods of prevention and control will require specialized chemical techniques and better knowledge of the causes of scaling. Consider the results of some simulated field deposition studies illustrating this need (Fig. 1). The studies utilized a Scale Deposition Test Cell* and each coupon was exposed to 8,000 ml of a 300 me/liter solution of the various types of mineral scale. All tests were conducted at 140F. Only the calcium sulfate and calcium carbonate deposited scale. The solution containing 300 me/liter of barium sulfate exhibited copious amounts of precipitate, but none of the precipitate adhered. The fluids from the effluents were also allowed to impinge on glass slides. Fig. 1 shows the relative adherence of the three types of scale on unetched glass. The barium sulfate failed to deposit in the same manner as the calcium carbonate and calcium sulfate solutions.

JPT

P. 1381ˆ
The Stimulation of a Tight, Very-High-Temperature Gas-Condensate Well
Authors: Economides Michael J. , Cikeš Marin , Pforter Harry , Udick Thomas H. , Uroda Pavle
Published: December 2007

Well KAL-5, completed in the Moslavacka Gora formation of the Pannonian basin in Yugoslavia, was tested at a flow rate of 75 Mscf/D [2124 std m3/d] of gas and 2.8 B/D [0.45 m3/d] of condensate and at a last bottomhole pressure (BHP) of 1,083 psi [7.5 MPa]. Pretreatment evaluation determined a reservoir permeability in the 0.003- to 0.004-md range. The high formation temperature (354°F [179°C]) poses problems for most fracturing fluids.

This paper presents a pretreatment analysis of the well, its geologic setting, and thermal and lithological characteristics as they relate to the choice of the fracturing-fluid system. An outline of the stimulation design and execution is included.

After a modest hydraulic fracture treatment, the well flowed for 21 days at a last flow rate of 1,925 Mscf/D [55×103 std m3/d] of gas and 117 B/D [18.7 m3/d] of condensate at a flowing BHP of 912 psi [6.3 MPa]. This substantial increase was apparently caused by the successful hydraulic fracture; geometric features of the fracture were estimated from interpretation of a posttreatment well test. Posttreatment evaluation assesses the effectiveness of the job, calculates the geometric dimensions and the conductivity of the fracture, and presents forecasts of future performance. Finally, the effects of the evolved gas condensate on the reduction of the apparent reservoir permeability are investigated and evaluated. A correlation between pressure, in-situ condensate saturation, and permeability is offered.
Plugging Thief Zones in Water Injection Wells
Authors: Robertson John O. , Oefelein Frank H.
Published: December 2007

Standard Oil Co. of California is improving performance of its California water floods by improving vertical coverage and reducing water cycling. This program is being achieved by selectively plugging thief zones in water injection wells with a mixture of silicic acid gel and either gilsonite or silica flour. Previous field trials over a period of 10 years with many other materials and techniques had not achieved the desired results. This article discusses the theory and placement techniques of silicic acid gel and presents the results of successful plugging operations in unsegregated, multilayered reservoirs consisting of interbedded soft shales and unconsolidated sands. The operations have been successfully conducted in slotted liner completions, gravel-packed liner completions and cemented gun- or jet-perforated liner completions. The silicic acid gel is prepared in the field, and the entire operation can be conducted with a production hoist and cement truck. Results of this program show conclusively that silicic acid gel in conjunction with proper placement techniques can be utilized to effectively plug thief intervals in water injection wells. This is expected to become a major factor in improving waterflooding efficiency with a resultant decrease in operating costs and increase in net profit.

Introduction

The economic success of a waterflood in thick, multilayered sands is dependent upon the efficiency of the displacement process. Control of vertical injection coverage is necessary for the maximum oil recovery and the reduction of excessive water cycling. Effective vertical coverage can be achieved by plugging thief intervals or with subsurface controls. The Vickers zone, Inglewood oil field, Calif., is an Unsegregated, 1,500-ft thick, multilayered reservoir consisting of unconsolidated sands interbedded with soft shales (Fig. 1). The average net sand thickness in this interval is 520 ft. The porosity and permeability values range from 28 to 36 percent and 500 to 2,500 md, respectively. Most injection wells are completed with either gravel-packed or slotted liners. In unsegregated zones this type of completion precludes the use of packers and subsurface beans to control or exclude injection into thief intervals. Within this zone, thief intervals are not confined to particular stratigraphic intervals; therefore, they cannot be excluded upon completion.

General Theory: Selective Plugging

Selective plugging in injection wells is not new to the petroleum industry. Cement, colloidal clays, inert solids, paraffins, waxes, organic resins and gels have long been utilized. Opinions differ as to the benefits obtained from using a selective plugging technique since apparently only the area adjacent to the wellbore is affected.
X-Ray CT and NMR Imaging of Rocks
Authors: Vinegar H.J.
Published: December 2007

Introduction

In little more than a decade, X-ray computerized tomography (CT) and nuclear magnetic resonance (NMR) imaging have become the premier modalities of medical radiology. Both of these imaging techniques also promise to be useful tools in petrophysics and reservoir engineering, because CT and NMR can nondestructively image a host of physical and chemical properties of porous rocks and multiple fluid phases contained within their pores. The images are taken within seconds to minutes, at reservoir temperatures and pressures, with spatial resolution on the millimeter and submillimeter level.

The physical properties imaged by the two techniques are complementary. CT images bulk density and effective atomic number. NMR images the nuclide concentration, Mo, of a variety of nuclei ( H, 19-F, 23-Na, 31-P, etc.), their longitudinal and transverse relaxation-time curves (t1 and t2 ), and their chemical shift spectra. In rocks, CT images both rock matrix and pore fluids, while NMR images only mobile fluids and the interactions of these mobile fluids with the confining surfaces of the pores.

Principles

CT uses an X-ray source that rotates around the sample to obtain one-dimensional projections of X-ray attenuation at different angles. From these projections, a crosssectional slice through the sample is reconstructed by computer. Finally. a three-dimensional image is reconstructed from sequential cross-sectional slices taken as the sample is moved through the scanner.

To obtain both density and effective atomic number, CT images are taken at two X-ray energies. One energy is high enough for the X-rays to be predominantly Compton-scattered and one is low enough for them to be mostly photoelectrically absorbed. A combination of the two images in the computer. on a pixel-by-pixel basis, generates separate images of bulk density and effective atomic number.

In NMR imaging, the sample is placed inside an intense, homogeneous, magnetic field, one preferably generated by a superconducting magnet. Radio frequency (RF) coils apply RF magnetic fields at the precise Larmor frequency to cause the particular nuclear species to precess. The RF coils then detect the signals generated by the precessing nuclei.

Spatial localization within the sample is obtained by x. y, and z magnetic-field gradient coils that cause nuclei in different parts of the sample to precess at slightly different frequencies. The resulting frequency-modulated signal is Fourier-transformed to obtain the spatial distribution of nuclear-spin density. Unlike CT, an image is obtained of the entire sample volume within the RF coil.

JPT

P. 257^
A Method for Simultaneous Determination of Permeability and Porosity in Low-Permeability Cores
Authors: Haskett Steven E. , Narahara Gene M. , Holditch Stephen A.
Published: December 2007

A new method for simultaneously determining the permeability and porosity of low-permeability cores is described. This method uses unsteady-state gas flow, which results in rapid tests. Equations are presented that describe the pressure response as a function of porosity and permeability. Comparisons of results to numerical simulations and conventional core-analysis methods are presented that verify the method 's accuracy.
Computerized Automation of Oilfield Production Operations: An Extensive 5-Year Study Into the Costs and Benefits
Authors: Jentsch W. A. , Marrs R. D.
Published: December 2007

Sun E&P Co. conducted an extensive 5-year study into the costs and benefits of installing and operating a supervisory-control and data-acquisition (SCADA) system. This paper briefly outlines the unit operations and the SCADA system installation, explains in detail the 5-year study, and highlights other intangible benefits provided by the system.
Temperature Dependence of L1/L2/V Behavior in CO2/Hydrocarbon Systems
Authors: Larson L. L. , Silva M. K. , Taylor M. A. , Orr F. M.
Published: December 2007

The temperature dependence of liquid/liquid (L1/L2) and liquid/liquid/vapor (L1/L2/V) phase behavior in CO2/hydrocarbon systems is investigated with a combination of measurements of L1/L2 and L1/L2/V phase compositions and calculations of two- and three-phase behavior with the Peng-Robinson equation of state (PREOS). New phase-composition data are reported for mixtures of CO2 with normal hexadecane (C16) and squalane (C30) and for mixtures of CO2 with methane (C1) and hexadecane. Measurements of three-phase pressures for mixtures of CO2 with C14, C16, and C30 are also reported. Calculations of L1/L2 and L1/L2/V phase behavior with the PREOS are compared with all available experimental phase-composition data for CO2/C1/C16 and CO2/propane (C3)/C16 systems. The PREOS predicts such behavior with reasonable quantitative accuracy if binary interaction parameters are selected to match L1/L2 data. Details of the disappearance of L1/L2/V behavior with increasing temperature are investigated with the validated PREOS. For the CO2/C3/C16 system, three-phase behavior disappears at a tricritical point. For the CO2/C1/C16 system, the disappearance occurs at the upper critical endpoint (UCEP) for the CO2/C16 binary system. Finally, qualitative similarities between CO2/crude-oil systems and the ternary systems described here are discussed.
Effect of an Aqueous Phase on CO2/Tetradecane and CO2/Maljamar-Crude-Oil Systems
Authors: Pollack N. R. , Enick R. M. , Mangone D. J. , Morsl B. I.
Published: December 2007

The effect of the presence of an aqueous phase on the phase behavior of the CO2/tetradecane and the CO2/Maljamar-crude-oil systems has been experimentally determined. Both the salinity and the amount of the aqueous phase were varied to test several methods of modeling. In the first technique, the amount of CO2 "lost" to the aqueous phase was determined using Henry’s law, decreasing the overall ratio of CO2 to hydrocarbons, while the Peng-Robinson equation of state (PR EOS) was used to determine the phase distribution of the hydrocarbon phases. In the second technique, the equation of state (EOS) was modified to predict the densities and compositions of not only the hydrocarbon phases, but also the aqueous phase. Simply accounting for CO2 solubility by incorporating Henry’s law, used in conjunction with the Poynting correction and an empirical factor for salinity, not only gave results nearly identical with the EOS approach, but also required less computational effort. Both methods gave good agreement with the experimental data.
Economic Considerations for Sizing Tubing and Power Cable for Electric Submersible Pumps
Authors: Powers Maston L.
Published: December 2007

Power consumption of an electric submersible pump (ESP) installation may be categorized into three components: the energy required to perform useful work, which is equivalent to the net hydraulic load divided by the product of pump and motor efficiencies; the energy absorbed by tubing friction, which is equal to the dissipated hydraulic energy divided by the efficiency product; and power-cable electrical losses. An improved design technique is presented that brings the first two categories into economic perspective. The interrelated effects of tubing friction, power-cable resistance, and motor voltage on ESP power consumption are demonstrated, as is the degree of desirability for using a motor of the highest available voltage. An equation, useful in making economic evaluations of alternatives, is developed for calculating power consumption for combinations of tubing size, power-cable size, and motor voltage. Variations of power consumption are illustrated graphically for various combinations of these three parameters. Also illustrated is the effect of the nature of a specific net hydraulic load—i.e., the product of rate, net lift, and specific gravity. Practical examples using the design techniques developed here are presented and comparisons made to designs based on common practice.
System Analysis for Sucker-Rod Pumping
Authors: Schmidt Z. , Doty D. R.
Published: December 2007

Pumping free gas in an oil well can significantly decrease the efficiency of a sucker-rod-pumping installation. Pump placement depth and use of a downhole gas/liquid separator (gas anchor) were found to be significant variables in improving the overall efficiency. A procedure is presented that shows when and to what degree the use of a gas anchor improves the efficiency of a sucker-rod pumping system. It was found that at lower pump intake pressures, the gas anchor usually improves efficiency, but at higher pump intake pressures, use of a gas anchor will produce no positive effect. Also, elevating the pump to the highest position that still allows proper pump loading was found to reduce the operating costs of a sucker-rod-pumping installation significantly. Finally, a procedure is presented to calculate directly the pump volumetric efficiency and required volumetric pump displacement rate.
Gas-Lift Design and Production Optimization Offshore Trinidad
Authors: Laing Cameron M.
Published: December 2007

Through a variety of field examples, this paper describes how increased production rates were obtained from gas-lift wells. These results were achieved through a wide range of activities, including special training for production operators, optimizing gas injection rates, modifying surface piping systems, identifying and replacing defective wireline-retrievable gas-lift valves, and improving gas-lift design techniques. A major modification of a standard gas-lift design technique is discussed in detail. The modification optimizes the depth of gas injection throughout the life of a well. An empirically derived chart, which relates valve spacing to the PI of a well, is also presented.
Early-Time Tight Gas Production Forecasting Technique Improves Reserves and Reservoir Description
Authors: Neal D. B. , Mian M. A.
Published: December 2007

For many tight gas wells producing without curtailment, the formation linear flow period can last for several years, leading to a new evaluation technique that utilizes commonly available producing rate data. This linear flow model, which states that the inverse of rate is proportional to the square root of time, leads to simple equations and graphical techniques for predicting the performance of low-permeability gas wells. The model is also useful in evaluating the reservoir quality and effectiveness of stimulation treatments. Accurate reserves and well-performance predictions can be made with as little as 6 months of production. In addition, the proposed method is easier to apply than other methods currently in use.
CASTEM—A New Automated Parameter-Estimation Algorithm for Single-Well Tracer Tests
Authors: Seetharam R. V. , Deans H. A.
Published: December 2007

The single-well chemical-tracer (SWCT) method has been used in more than 140 tests since 1968 to determine residual oil saturation (ROS) after waterflooding. Interpretation of the test involves matching tracer data from the field by use of computer simulation programs. As the complexity of the simulator model increases, the number of trial runs needed to fit field data satisfactorily increases rapidly. The conventional fitting procedure can thus become very cumbersome and can involve prohibitive computer costs. A new method has been devised to model tests in heterogeneous formations. These rigorous simulators have been replaced by simple response functions capable of being used in a standard parameter-estimation routine. Matching the tracer data now involves function evaluations rather than full simulator runs, resulting in a large reduction in computing time.

The algorithm developed here includes many frequently used tracer test models. The new method has been used to explain both simulated and actual field data from tracer tests conducted in multilayer reservoirs. The choice of an appropriate model to explain a specific set of field data may be a qualitative decision, especially in the absence of other supportive physical evidence. However, the variation in the effective ROS predicted by the different models was found to be quite minimal and within the limits of accuracy of the test.
Dual-Burst Thermal Decay Time Logging Principles
Authors: Steinman D. K. , Adolph R. A. , Mahdavi M. , Preeg W. E.
Published: December 2007

The dual-burst thermal-neutron-decay-time (TDT™) tool brings two enhancements to pulsed-neutron capture logging. The first is a realistic physical model of pulsed neutron decay curves that accounts explicitly for the effects of neutron diffusion and decay in both the wellbore and the formation. The second is the dual-burst system itself, which permits excellent statistical precision with minimal dead-time losses. This paper discusses the physics of the model, operation of the tool, important mathematical considerations for optimum use of the tool, and a demonstration of the tool performance in a laboratory simulation of a log-inject-log (LIL) operation.
Use of Inhibitors for Scale Control in Brine-Producing Gas and Oil Wells
Authors: Rogers L. A. , Varughese K. , Prestwich S. M. , Waggett G. G. , Saliml M. H. , Oddo J. E. , Street E. H. , Tomson M. B.
Published: December 2007

Field and laboratory work sponsored by the Gas Research Inst. (GRI) and the U.S. DOE showed that calcium carbonate (CaCOз) scale formation in waters produced with natural gas and oil can be prevented by injection of phosphonate inhibitor into the formation, even if the formation is sandstone without calcite binding material. Inhibitor squeeze jobs were carried out on the DOE's geopressured/geothermal Gladys McCall brine/gas well and GRI's coproduction wells in the Hitchcock field. After the inhibitor squeeze on Gladys McCall, the well produced more than 5 million bbl [800× 103 m3] water at a rate of about 30, 000 B/D [4770 m3/d] without CaCOз scaling. Before the inhibitor squeeze, the well could not be produced above 15, 000 B/D [2385 m3/d] without significant scale formation. In the GRI brine/gas coproduction field tests, inhibitor squeezes have been successfully used to prevent scaling. Laboratory work has been conducted to determine what types of oilfield waters are subject to scaling. This research has led to the development of a saturation index and accompanying nomographs that allow prediction of when scale will develop into a problem in brine production. Core samples from both fields were used in laboratory studies. Analytical methods to analyze inhibitors in brine at low levels were extended. A complete history of field development and the laboratory backup experiments is included in this paper.
Evaluation of Directional Survey Errors at Prudhoe Bay
Authors: Dubrule Olivier , Nelson Philip H.
Published: December 2007

More than 1,000 directional surveys from wells in the Prudhoe Bay field are used to examine differences in well location at 8,000 ft [2438 m] subsea, as measured by gyroscopic and magnetic surveying instruments. The lateral, radial, and vertical errors are plotted as a function of horizontal offset. Mean lateral differences appear to be about 100 ft [30 m]. Drillstring magnetization causes magnetic surveys to read north of gyros. Vertical and radial differences are negatively correlated, are chiefly a result of inclinometer errors, and are on the order of tens of feet. The Wolff-de Wardt (WdW) error model, with small modifications, does a good job of quantifying the error magnitudes, of describing the dependence of error upon horizontal offset, and of producing the ellipses of uncertainty.
Effects of Nonlinear Reservoir Compaction on Casing Behavior
Authors: Chia Y. P. , Bradley D. A.
Published: December 2007

Depletion of overpressured, undercompacted reservoirs can cause large reservoir pressure drops and sediment compaction, which may result in casing deformation and well failure. To predict soil and casing deformation during depletion, a finite-element model was developed. Nonlinear elastic and plastic behavior of the soils and slippage along the wellbore boundary are major advancements in this study. This axisymmetric model is composed of casing wall, cement column, slippage interface, and sediments from 11,400 to 13,200 ft [3475 to 4025 m] in depth with a radius of 3,400 ft [1035 m]. This study features a process of concurrent fluid flow, nonlinear elastic and plastic soil deformation, slippage from the wellbore boundary, and casing deformation.

The modeling results show that the decline in near-wellbore reservoir pressure during depletion causes vertical compaction in both the sand reservoirs and the confining shale formations. Slippage next to the wellbore decreases the axial shear load placed on the casing by the sediments. Nonlinear elastic and plastic soils show a greater tendency for casing deformation with depletion than do linear elastic soils. Axial strains in the casing above the yield strain eventually developed as near-wellbore reservoir pressure was allowed to decline to a minimum. Because this effect is quantified, the production rate may be held to a safe maximum so that the operating limits of the casing are not exceeded. Criteria are given to improve both completion design and production rate specification.
Complex Dielectric Interpretation of 20-MHz Electromagnetic Logs
Authors: Sims J. C. , Cox P. T. , Simpson R. S.
Published: December 2007

An interpretation technique for the 20 × 106-cycle/sec [20-MHz] dielectric log based on the complex Lichtenecker-Rother (LR) equation is proposed. The equation is shown to be an adequate model of quarry rocks and is applied to field logs from the California coastal basins. The results are significantly better than those obtained with other techniques. The major disadvantage is that core data are required for calibration in each reservoir.
Coiled-Tubing Logging System
Authors: Howell E. P. , Smith L. J. , Blount C. G.
Published: December 2007

Techniques have been developed to use coiled tubing containing a seven-conductor wireline to facilitate logging operations. Equipment has been designed to permit the connection of conventional logging tools to the tubing and the recording of logs. Operating techniques have been developed and applied under various wellbore conditions. The system allows traditional log measurements in a well while wellbore conditions are controlled. Advantages of the system include reduced wellbore pressure during perforation to maximize perforation performance; lubrication during pulling or pushing a logging tool through a borehole so that a more uniform velocity can be maintained with a logging sonde; continued circulation and thus borehole stability during logging; temperature reduction for improved reliability of logging sonde electronics in hot holes; and more stable positioning of perforation equipment. The ability of coiled tubing to push tools down highly deviated or horizontal wellbores makes logging or perforating feasible in these wells. Expenses can often be reduced with coiled-tubing logging because a rig is unnecessary during many operations.
The Effects of Multiphase Flow on the Interpretation of Pressure Buildup Tests
Authors: Ayan Cosan , Lee W. J.
Published: December 2007

A two-dimensional (2D), three-phase, variable-bubblepoint reservoir simulator was developed to simulate pressurebuildup tests involving multiple phases. The simulation indicated that nonuniform saturation distributions throughout the drainage area can cause erroneous interpretations when single liquid-phase techniques, as modified by the Perrine-Martin theory, are used for the analysis.
Enhanced Resolution Processing of Compensated Neutron Logs
Authors: Galford J. E. , Flaum C. , Gilchrist W. A. , Duckett S. W.
Published: December 2007

Compensated neutron logging (CNLSM) uses a two-detector system that was developed to reduce borehole effects. The ratio of counting rates from the detectors provides the basic tool response from which a porosity index is obtained. Each detector in this system has a different vertical resolution because of its spacing. A new method of processing the counting rates has been developed to enhance the vertical resolution capabilities of the neutron porosity index by exploiting the better vertical resolution of the near detector. Because no additional or new measurements are required, data from older wells can easily be re-evaluated.

Results from the new method have been compared with microspherically focused logs (MicroSFLSM) and electromagnetic propagation logs (EPTSM). They show repeatable thin-bed resolution on the order of 1 ft [0.3 m] for data sampled at 6-in. [15-cm] intervals; the typical vertical resolution from ratio processing is approximately 2 ft [0.6 m]. The statistical precision of the high-resolution processing is superior to that of the standard ratio method.

An additional parameter, obtained with the new processing method, provides information about borehole effects. This parameter can be used for qualitative indications of gas when invasion is not deep and environmental effects are not large.

The new method has been applied successfully in carbonate and laminated sand formations. Studies show that thin beds can be detected in high-porosity formations where normal processing has significant statistical variations resulting from reduced counting rates.
An Experimental and Theoretical Study of a Coupling Mechanism Between Longitudinal and Torsional Drillstring Vibrations at the Bit
Authors: Aarrestad Thor Viggo , Kyllingstad Åge
Published: December 2007

A mechanism that couples longitudinal and torsional drillstring vibrations at the bit was studied. Torsional vibrations are associated with dynamic variations of the rotational bit speed. When a roller bit runs over a multilobed pattern, these speed variations have been shown to affect the input of longitudinal vibrations. The theory for this coupling mechanism is verified experimentally by high-rate data of near-bit accelerations and torque recorded in a 1000-m [3,280-ft] -deep well.
Variable-Skin and Cleanup Effects in Well-Test Data
Authors: Larsen Leif , Kviljo Knut
Published: December 2007

Methods to analyze well-test data influenced by variable-skin and cleanup effects are introduced, with emphasis on verifications of consistency in drawdown and buildup data. It is shown that a stable cleanup trend can be modeled by a simple hyperbolic skin factor in solutions for wells with constant skin. It is also shown that if the skin effect stabilizes at constant values within the general cleanup trend, then segments of data fitting a model with constant skin should be detectable. In some cases, repetitions of such segments can be used to estimate the formation flow capacity and the well cleanup rate. We also discuss how a gradual reduction in the skin effect in drawdown data can produce a false semilog straight line and lead to gross overestimation of flow capacity and skin. Well cleanup can produce constant or nearly constant bottomhole pressures (BHP's) during periods of constant-rate production, thus giving a false impression of pressure support in the reservoir. Methods presented will help to recognize whether a well is strongly influenced by either gradual or abrupt cleanup effects.
The Application of New Approaches for Shale Management in a Three-Dimensional Simulation Study of the Frigg Field
Authors: Hazeu Godard J.A , Krakstad Ole S. , Rian Dag T. , Skaug Mari
Published: December 2007

The Frigg field is a major North Sea gas reservoir composed of turbiditic sediments. This paper describes the detailed geologic modeling and three-dimensional (3D) reservoir simulation of the field.

A geologic model containing sand lobes and intercalating shales has been defined from seismic and well data. Special attention was paid to the realistic modeling of the shales. The more continuous (deterministic) shales between the turbiditic sand lobes of the reservoir were directly implemented in the model as horizontal flow barriers. The more discontinuous shales within the lobes were modeled with the method of Haldorsen and Lake1 and Begg and King.2 This method uses statistical geologic information and well data to calculate effective vertical permeability. The simulator was built as a 3D, two-phase (gas/water) model. Field data for 8 years of production were matched. A good match of both fluid levels and pressures was obtained. This reservoir study demonstrates that the impact of the shales on the reservoir behavior in general and the movement of the gas/liquid contact (GLC) in particular is essential.
Total Organic Carbon Content Determined From Well Logs
Authors: Fertl Walter H. , Chilingar George V.
Published: December 2007

Total organic-carbon (TOC) content present in potential source rocks significantly affects the response of various well logs. This paper discusses and illustrates well-log anomalies caused by TOC as observed on various wireline measurements, including resistivity (or conductivity), acoustic, nuclear (density and neutron), gamma ray, natural gamma ray spectra, and pulsed neutron [sigma and carbon/oxygen (C/O) ratio].

Field examples of these well-log responses in open and/or closed wellbores are presented from several countries. Several correlations between TOC and individual and/or combinations of various logging responses are also reviewed.
Application of Unconventional Techniques in Constructing an Integrated Reservoir Simulation Model for Troll Field
Authors: Kydland T. , Haugan P. M. , Bousquet G. , Havlg. S. O.
Published: December 2007

A number of unconventional techniques were used for constructing an integrated three-dimensional (3D), three-phase numerical reservoir model of the huge Troll field. The selected techniques included corner-point geometry (CPG), non-neighbor connections between grid cells, local grid refinement, improved vertical equilibrium (VE) description, and oilwell coning functions. By combining these techniques, an efficient model, capable of handling several complex reservoir problems simultaneously, was developed. This model became a flexible tool for reservoir management planning.
Proppant-Pack and Formation Impairment During Gas-Well Hydraulic Fracturing
Authors: Roodhart L. P. , Kulper T. O. H. , Davies D. R.
Published: December 2007

Equipment has been constructed to give a realistic laboratory simulation of the in-situ conditions during and after a hydraulic fracturing treatment of tight gas reservoirs (TIGRE). The equipment measures the permeability of both the "natural" core material and the proppant pack with gas under in-situ conditions before and after exposure to fracturing fluid. The rate of cleanup of the proppant pack and the core sample is measured after the fracturing fluid has broken.

Various fracturing fluids commercially available from the major service companies have been evaluated. Little damage to the proppant/rock interface has been measured, but massive damage to the proppant pack was observed. The damage is caused by fracturing-fluid residue, filter cake, and non-Darcy flow effects. This damage is observed only in the experiments described above and has not been reported in other less sophisticated laboratory simulations of the fracturing process.

The least damaging of the commercially available products tested has been identified. Procedures have been developed for placing "overdesigned" (or increased-conductivity) proppant packs during field hydraulic fracturing treatments. This has resulted in large increases in well productivity during field treatment, which is particularly noticeable during the early (transient) production phase. It is concluded that there is scope for the development of less damaging fracturing fluids to optimize economics.
New Pressure-Transient Analysis Model for Dual-Porosity Reservoirs
Authors: Olarewaju J. S. , Lee W. J.
Published: December 2007

This paper presents a new analytical model for interpreting pressure-transient tests for wells producing from dual-porosity reservoirs. This model includes unsteady-state matrix flow and incorporates the effects of wellbore storage, skin, and, for gas reservoirs, desorption. The model is applicable to bounded and infinite-acting reservoirs.