bluuebunny/crossref_metadata_2025 huggingface dataset:
A Laboratory and Field Evaluation of the CO2 Huff ’n’ Puff Process for Light-Oil Recovery
Authors: Monger T. G. , Coma J. M.
Published: December 2007

Cyclic CO2 injection for enhanced recovery of light crude oil is investigated. Results from watered-out Berea corefloods and 14 field tests demonstrate that first and second cycles recover waterflood residual oil. Factors that may improve performance include larger reservoir slug volume, soak period, thicker interval, and lower prior water cut.
Interpretation of Pressure-Buildup Responses in Gas-Condensate Wells
Authors: Jones J. R. , Vo D. T. , Raghavan R.
Published: December 2007

Methods to analyze buildup responses in gas-condensate reservoirs producing below the dewpoint pressure are examined. Two analogs to compute formation flow capacity and average reservoir pressure are presented. These analogs are based on the steady-state theory (developed by O'Dell and Miller and later modified by Fussell) and the single-phase-flow theory (which ignores the existence of the two phases). The mechanical skin factor can be computed from the derivative response by computing the appropriate dimensionless pseudopressure.
A Method for Analyzing Pulse Tests Considering Wellbore Storage and Skin Effects
Authors: Dinges Darrell D. , Ogbe David O.
Published: December 2007

Pulse testing is used to determine the transmissivity and storativity of a reservoir. A pulse test is conducted by creating a series of flow-rate changes at an active (pulsing) well and observing the pressure response at a nearby observation (responding) well.

Previous studies have shown that wellbore storage and skin effects should be accounted for when analyzing a pulse test. This study presents the data required for the analysis and design of pulse tests considering wellbore storage and skin effects at the pulsing or responding well, for tests run with unequal producing and shut-in periods. Before this study, data were limited to tests run with equal producing and shut-in periods. The use of unequal producing and shut-in periods is necessary to optimize test design and analysis. To reduce the amount of data required in this method, a new correlation is used and a set of regression coefficients is provided. A field example is included to illustrate how to use this method.
Investigation of Foam Stability in Porous Media at Elevated Temperatures
Authors: Isaacs E. Eddy , McCarthy F. Clare , Maunder J. Darol
Published: December 2007

This paper describes a laboratory study of the factors controlling the formation and breakdown of foams in porous media at elevated temperatures. The degradation of a foam when gas injection was discontinued involved the gradual transformation of a foam with a noncondensable gas phase (gas foam) to a foam with steam as the gas phase (steam foam). The ability to prevent release of the noncondensable gas phase was strongly influenced by surfactant type and concentration. The formation of steam foams in the absence of noncondensable gas was a critical function of steam velocity and permeability. Surfactant concentration and chain length, salinity, and the presence of oil were important variables in determining mobility reduction of steam. Increased oil recovery from cores undergoing steam displacement was obtained when surfactant slugs were injected with and without noncondensable gas. The presence of a noncondensable gas led to the formation of a more effective and durable foam.
Low-Temperature Oxidation of Viscous Crude Oils
Authors: Fasslhl Mohammed R. , Meyers Kevin O. , Baslle P. F.
Published: December 2007

During in-situ combustion, oxygen can bypass the flame front and react with oil temperatures that are relatively low compared with those in combustion. These reactions, called low-temperature oxidation (LTO), can adversely affect the crude's physical and chemical properties and result in lower oil recovery. This paper presents laboratory study results on the LTO of four oils, ranging from 31.1 to 10.1° API and from 14 to 54, 300 cp dead-oil viscosity at 85°F. They include two biodegraded oils, a mature crude, and an immature heavy oil. The LTO of these oils is reported as a function of reaction time, oxygen partial pressure, and temperature. LTO increased oil viscosity and density. For the 31.1 °API oil, these increases are minor and should have insignificant effects on process performance. For the heavier oils, however, the viscosity of the oxidized oils increases exponentially with increasing extent of oxidation, XO2 Relatively minor oxidation (40 mgO2/g oil) results in a six-fold increase in viscosity. The rate of viscosity increase depends on an oil's API gravity, origin, and composition.

Compositional changes accompanying LTO are also discussed. LTO is shown to increase the asphaltene content of the oxidized oils significantly, and a correlation is presented between asphaltene content and XO2 Simulated distillation results demonstrate that LTO does not significantly affect the volatility or carbon number distributions of either the light or heavy oils. The observed physical and compositional property changes are consistent with the LTO mechanism proposed in the literature: oils → resins → asphaltenes/coke.
Molecular Degradation, Injectivity, and Elastic Properties of Polymer Solutions
Authors: Southwick J. G. , Manke C. W.
Published: December 2007

New features of polymer rheology in porous media were observed when hydrolyzed Polyacrylamide (HPAM) solutions were flowed through sandstone, gravel packs, and glass-bead packs at high rates. Independent measurement of elongational viscosity, µe, with a ductless-siphon technique demonstrates that the enhanced resistance seen at high flow rates is not directly proportional to µe. Furthermore, significant permeability trends in resistance factor and mechanical degradation are observed when plotted vs. strain rate. When these results are translated to field flow rates and geometries, they indicate that HPAM solutions can be injected at reasonable injection pressures with minimal viscosity losses, provided that perforated completions are designed with either sufficient perforation density or perforation size.
The Coefficient of Isothermal Compressibility of Black Oils at Pressures Below the Bubblepoint
Authors: McCain William D. , Rollins John B. , Lanzi Alejandro J. Villena
Published: December 2007

Values of oil compressibility are required in all solutions of transient fluid-flow problems. Oil compressibility can be calculated directly if reservoir-fluid studies are available. In this paper, empirical equations are presented to provide accurate estimates of the compressibility of black oil at pressures below the bubblepoint when laboratory measurements are not available.

The equations were developed with data from reservoir-fluid studies of 260 oil fields worldwide. The data encompassed a wide range of oil compressibilities, surface-gas specific gravities, stock-tank oil gravities, solution GOR's, reservoir pressures, reservoir temperatures, and bubblepoint pressures
Effect of Drilling Fluids on Rock Surface Properties
Authors: Cuiec L.
Published: December 2007

This paper discusses the wettability change induced by contact between porous media and drilling fluids and the possibility of eliminating such alterations by cleaning. Three porous media were studied (sandstone, shaly sandstone, and carbonate), as well as various drilling fluids (oil- and water-based). Initially strongly water-wet (hydrophilic) and initially neutral rock/oil/brine systems were evaluated. Wettability was estimated by a test based on spontaneous and forced displacement experiments.

The results show that all the oil-based drilling fluids used induce a wettability change inasmuch as the rock is initially water-wet. The rock surface properties are observed to be affected at a distance > 0.6 in. [> 1.5 cm] from the rock/drilling-fluid interface. Cleaning procedures with toluene and methanol circulations can return the rock surface to the original wettability state, but the permeability remains affected. Water-based drilling fluids made no appreciable change in the wettability of the three initially highly hydrophilic porous media.
Oil Recovery by Gravity Segregation
Authors: Richardson J.G. , Sangree J.B. , Sneider R.M.
Published: December 2007

Technology Today Series articles provide useful summary informationon both classic and emerging concepts in petroleum engineering. Purpose: To provide the general reader with a basic understanding of a significantconcept, technique, or development within a specific area of technology.

Gravity segregation of oil from gas- or water-invaded regions is anefficient natural recovery mechanism if conditions are favorable. Favorableconditions include high vertical permeability, an advantageous relation betweenrelative permeability and oil saturation, high vertical continuity, a largedensity difference, low oil viscosity, and long oil drainage times after aregion has been invaded. Recoveries as high as 87% of the original oil in place(OOIP) have been observed in gas-invaded regions of the Hawkins field and morethan 80% OOIP has been recovered from water-invaded parts of the East Texasfield.

Theory for calculating the vertical segregation of oil first was presentedby Cardwell and Parsons in 1949. Equations were derived from Darcy's law andthe continuity equation, assuming that the driving force for oil movement isthe hydrostatic head caused by density differences. Thus, the theory firstassumes that pressure gradients caused by movement of the displaced fluid, gasor water, is negligibly small. This is usually valid, especially at low oilsaturations. The second tacit assumption is that capillary pressure gradientscaused by saturation gradients are small. Calculations show that ignoringcapillary pressure gradients usually results in errors in the average oilsaturation of less than 1% PV because capillary pressure gradients becomesignificant only as the equilibrium saturation distribution above the gas/oilcontact (GOC) or water/oil contact is approached.
Computation of the Pseudoskin Factor Caused by a Restricted-Entry Well Completed in a Multilayer Reservoir
Authors: Yeh N. , Reynolds A. C.
Published: December 2007

This work considers flow to a restricted-entry well in a single- or multilayer reservoir where crossflow occurs between reservoir layers. A simple algebraic expression for approximating the pseudoskin factor caused by restricted entry is presented. It is shown that, for practical purposes, this equation yields sufficiently accurate estimates of the pseudoskin factor regardless of the location of the open interval. This work also extends single-layer results of interest in well testing to the multilayer case and shows that if sufficient data are available, the results of this work can be used to prepare a complete analysis of well testing pressure data obtained at a restricted-entry well.
Critical Rate for Water Coning: Correlation and Analytical Solution
Authors: Høyland Leif A. , Papatzacos Paul , Skjaeveland Svein M.
Published: December 2007

Two methods are presented for predicting critical oil rate for bottomwater coning in anisotropic, homogeneous formations with the well completed from the top of the formation. The first method is based on an analytical solution where Muskat's assumption of uniform flux at the wellbore has been replaced by that of an infinitely conductive wellbore. The potential distribution in the oil zone, however, is assumed unperturbed by the water cone. The method is derived from a general solution of the time-dependent diffusivity equation for compressible, single-phase flow in the steady-state limit. We show that very little difference exists between our solution and Muskat's. The deviation from simulation results is caused by the cone influence on potential distribution.

The second method is based on a large number of simulation runs with a general numerical reservoir model, with more than 50 critical rates determined. The results are combined in an equation for the isotropic case and in a single diagram for the anisotropic case. The correlation is valid for dimensionless radii between 0.5 and 50 and shows a rapid change in critical rate for values below five. Within the accuracy of numerical modeling results, Wheatley's theory is shown to predict the correct critical rates closely for all well penetrations in the dimensionless radius range from 2 to 50.
Gas Supply and Requirements in California
Authors: Bradfield S.A.
Published: December 2007

To understand properly the gas supply and demand situation in California one significant fact must be kept in mind: To the California householder, gas is the universal fuel. He looks to the state's gas utility companies to supply him with fuel for househeating, cooking and water heating, and to a somewhat lesser extent, refrigeration. His dependence on gas is traditional since California, unlike many other parts of the country, does not have major coal deposits.

California's cities are young, almost as young as the petroleum industry which supplies them with natural gas. The major portion of the state's growth has taken place since the turn of the century, particularly in the more populous southern half. The two world wars, the intervening period of boom and depression, and the post-World War II period have seen an unprecedented population increase and the development of an enormous west coast industrial empire. Fuel for both domestic and industrial growth has been supplied almost exclusively by the expanding petroleum industry through equally expanding facilities of the state's gas utility companies. To tell the story of the growth in California's gas requirements is the prime purpose of this paper.

Increase in Requirements

California's modern history is the story of many booms, but it was not until the first World War that its major industrialization and attendant domestic growth began. In 1920, the beginning of Southern California's greatest period of development, the state's population was 3,426,861. During the ensuing 30 years, population more than tripled to a present total of 10,586,223.

The most rapid increase in population has occurred in the southern portion of the state, including Los Angeles and contiguous territory. The 14 counties comprising the southern half of California have increased in population from 1,512,839 in 1920 to 6,095,394 in 1950.

Though the increase in California's population has been rapid, the use of natural gas has more than kept pace. In 1935 there were 1,486,640 general service customers in the state who consumed 71,638,340 Mcf of gas. In 1950, there were 2,880,180 who used 249,315,565 Mcf, an increase in the number of customers of 93 per cent but an increase in gas consumption of 248 per cent. Obviously, the increased number of gas users does not tell the whole story of the firm gas load increase.

To further illustrate the increased gas usage by California householders, the average general service customer in Southern California used about 83 Mcf of gas during the relatively cold year of 1949.
Physical Deliverability of Gas Reserves
Authors: Gardescu Ionel I.
Published: December 2007

Introduction

The rate at which oil and gas can be produced over the life of a field is of major importance in ascertaining the purchase value of a property, the security of a loan, or the assurance of a steady supply of oil and gas to a pipeline. This paper deals only with the problem of predicting the future production of gas wells.

The deliverability study presented is an illustration of a workable method of estimating the volume of gas-well gas available under certain conditions of field performance, contractual obligations and other physical and regulatory limitations. The study is based on exhibits and accompanying supporting data prepared for and submitted to the Federal Power Commission in a recent Certificate Case of Public Convenience and Necessity.

In connection with the estimation of gas reserves, two general terms are being used which, to avoid confusion, should be defined.

Recoverable reserves are estimates made of the ultimate volume of gas that can be produced profitably from a reservoir. In general, there is no restriction imposed as to the period over which the gas will be recovered or the rate of flow that has to be maintained.

Deliverable reserves are estimates made of the volume of gas that a reservoir or well can deliver during a given period of time, at a specified contractual rate of flow, against a certain wellhead pressure, under the prevailing physical conditions of the gas reservoir and the status of well development in the field, taking also into account any other contractual and applicable regulatory restrictions.

One of the main factors involved in the estimate of delivery is the computation of "physical deliverability" which shows the maximum rate at which a well can be produced under the existing characteristics of the reservoirs and lease operations. Thus, the physical deliverability is a ceiling beyond which a well or reservoir cannot be produced under given conditions. However, other restrictions may further curtail the rate of delivery below the estimated maximum physical deliverability volume.
Viscoelasticity of Crosslinked Fracturing Fluids and Proppant Transport
Authors: Acharya A. Ruma
Published: December 2007

In hydraulic fracturing treatments, the success of the treatment strongly depends on the proper placement of proppant particles in the fracture. "Proper placement" means the packing of the fracture to achieve maximum conductivity of gas/oil through the fracture into the wellbore. The placement of the proppants along the fracture is based on design equations where sand transport velocity is related to the rheological parameters of the fracturing fluid and characteristics of the proppant particle, such as size and density.

The present work describes the theoretical transport equations that take into account the elasticity of the fluid in predicting proppant settling rate in the fracture. It presents the rheological data of commonly used fracturing fluids (titanate and borate crosslinked), including viscous and elastic parameter measurements made with a Rheometrics Pressure Rheometer™ (RPR) and Rheometrics Mechanical Spectrometer™ (RMS-800). These data show some important differences between borate crosslinked gels and titanate crosslinked gels. The paper also presents experimental data of proppant settling rates in various fracturing fluids and how these can be correlated with rheological parameters obtained in this work. The difference in rheology between borate and titanate gels was correlated with the difference in settling rates of proppants in these two gels. The theoretical and experimental work presented here led to the conclusion that the model for proppant placement in a hydraulic fracture should include: (1) proppant characteristics, (2) viscous rheological parameters (K and n), (3) elastic parameters (complex dynamic viscosity) from linear viscoelastic constitutive equation, and (4) normal stress difference from nonlinear viscoelastic constitutive equation. The influence of crosslinked-polymer-gel network structure on proppant transport is also discussed.
Economic Evaluation of a CO2 EOR Flood at the Rock Creek Field, Roane County, West Virginia
Authors: Brummert A. C. , Ammer J. R. , Watts R. J. , King P. , Boone D. A.
Published: December 2007

The U.S. DOE Morgantown Energy Technology Center and the Pennzoil E&P Co. predicted the recovery and economic potential of a full-field, CO2 miscible EOR flood at the Rock Creek field, Roane County, WV. Data used in this evaluation were obtained from two miscible CO2 Rock Creek field tests: (1) a pilot test consisting of two contiguous normal five-spot patterns, each containing 10 acres [4 ha], and (2) a 1.55-acre [0.63-ha] normal four-spot minitest. Core data from the eight injection wells and three observation wells were used to determine reservoir input parameters, and fluid samples were analyzed to obtain fluid properties. A predictive model was used to calculate oil recovery and project economics. The model’s base-case run showed that an oil price of $39/bbl [$245/m3] was required to produce a 15% discounted cash flow rate of return (DCF ROR). A sensitivity study was then conducted on operating parameters [i.e., pattern size, water-alternating-gas (WAG) ratio, total HCPV of WAG injected, and injection rate] and economic parameters (e.g., oil price and CO2 cost) to determine their effect on project performance and project economics.
Partially Decoupled Modeling of Hydraulic Fracturing Processes
Authors: Sattarl A. , Puchyr P. J. , Bachman R. C.
Published: December 2007

A new method of partial decoupling of the problem of modeling a hydraulic fracture in a reservoir is described. This approach has significant advantages over previous methods with either fully coupled or completely uncoupled models. Better accuracy can be achieved in modeling the fracture propagation, and the new system is very efficient and versatile. Virtually any reservoir model can be used for predicting postfracture productivity. Examples of single- and multiphase applications for modeling fractured wells are discussed.
Nonisothermal Effects in Water-Injection Well Tests
Authors: Barkve Tor
Published: December 2007

This paper discusses models for one- and two-phase injection-well tests where the injected fluid has a temperature different from that of the reservoir fluid. After a brief discussion of the relative significance of different nonisothermal effects, an integral form of the model equations is used to develop approximate analytical expressions describing temperature and pressure in the reservoir during injection. The expressions are valid for a general variation in viscosity with temperature, and different analytical viscosity functions are used to study the influence of this variation.
Shale/Mud Inhibition Defined With Rig-Site Methods
Authors: Chenevert M. E. , Oslsanya S. O.
Published: December 2007

The successful drilling of troublesome shale requires evaluation of the shales and muds during the drilling process so that the proper methods and muds can be selected. With rig-site testing in mind, six tests were studied for their usefulness in defining the severity of the shale/mud chemical reaction. All tests showed some value in the analysis of wellbore problems and solutions; however, the swelling, rolling, and cation-exchange-capacity (CEC) tests proved most useful.

The swelling test uses a newly developed device to describe the early-time swelling properties of native or recompacted shale and provides an analytical method for classifying shales according to their reaction rates. In general, soft shales have a short reaction time, which increases with its hardness. This test also shows the inhibition state of a mud and can therefore be used in mud monitoring and mud-treatment design. The rolling test provides useful information on the dispersion tendencies of a shale-cuttings/mud mixture, and the CEC test provides basic information on the effective clay content of a shale.

This paper discusses techniques used to evaluate shales and muds at the rig site and presents the procedures, results, and parameters that affect each technique. Information concerning a new device for measuring shale swelling and the procedure for reconstituting shale cuttings is given.
Modern Solids Control: A Centrifuge Dewatering-Process Study
Authors: Wojtanowicz Andrew K.
Published: December 2007

The concept of a modern solids-control system for drilling rigs is introduced and experimentally investigated. The system incorporates a conventional solids-control arrangement followed by a diversion of part of the drilling mud for chemical conditioning and centrifugation. The dewatering effluent is returned to the mud system makeup-water storage. The dewatered colloidal solids are then stabilized by being mixed with the shaker discharge and the surrounding soils. The system can provide an effective control of colloidal-solids concentration in drilling muds. It can also minimize the volume of drilling waste.

The new process was examined in full-scale experiments to evaluate process efficiency and to identify the effects of field installation, operational variables, solids classification before dewatering, dilution, and the stability of the dewatering and its sensitivity to chemical dosage. In the chemical destabilization tests, a successful treatment was found for flowline samples of five different drilling-mud systems. The conceptual design of the modern solids-control system is presented and discussed. This process is also related to conventional solids-control and wastewater treatments.
Simplified Slurry Design Increases Wellsite Success
Authors: Grant W. H. , Dodd E. L. , Gardner C. A.
Published: December 2007

Highly flexible cement systems can be designed to accommodate a broad range of well conditions with a relatively small number of additives that are readily available from any cementing service company. Fluid-loss additives can be used with dispersants and small amounts of KCl (when applicable) to design slurries for most primary cementing applications—e.g., cementing in CO2 and salt-zone environments and prevention of annular flow after cementing. This paper illustrates how materials and slurry properties that are easily specified can be used to improve wellsite success.
Wellsite Information Transfer Specification (WITS) for Digital Rig-Site Data
Authors: Jantzen R. E. , Foreman R. D , Keltner L. , McCoy R. S.
Published: December 2007

Information of many kinds, including drilling and mud-logging parameters, is transmitted electronically from rigs to central sites. The format of the transmitted information depends, at present, on the business entities involved in the information-transfer transaction. Many different formats exist, decreasing the overall utility of information obtained at the rig site and increasing processing costs for the industry. Standardization of formats for information content and telecommunication requirements was attempted by the Information Transfer Committee (ITC), a subcommittee of the Intl. Assn. of Drilling Contractors’ (IADC's) Rig Instrumentation and Measurement (RIM) Committee, which formulated a set of guidelines addressing the broad needs of the industry. This paper explains the rationale for the standardization effort; outlines the process by which the specification was established; and describes the requirements, concept, components, and benefits of the resulting WITS.
A New Method of Coating Oilfield Core for Laboratory Studies
Authors: Menzie D.E. , Dutta S. , Shadizadeh R.S.
Published: December 2007

A new method has been developed for coating oilfield core for laboratory studies. It consists of applying a steel coating and aluminum wraps around the outer surface of a core. The strength of the coating, the short time needed to apply it, and its low cost are the major advantages of this new method.

Introduction

Laboratory core studies are commonly conducted to evaluate reservoir rock properties. In the past, epoxy, wax, and plastic coatings of cores have been used conventionally to conduct experimental studies. Because of various problems, such as leakage or fractures even under low pressures in these and other conventional coatings, a new method of coating and mounting a reservoir rock core was investigated. This new method of core coating and mounting was tested for leaks, fractures, and pore invasion and was found not to have leaks or fractures or to invade pore spaces up to a test pressure of 400 psig [2758 kpa]. The cores were not tested for higher pressures, but these metal-coated cores are expected to withstand a pressure of about 1,000 psig [6895 kPa] safely. Experiments may also be conducted at high pressures ranging from 2,000 to 3,000 psig [ 13.8 to 20.7 MPa] with an increased number of coatings and uniformly tight mounting connections.
Relative Permeability From Unsteady-State Displacements With Capillary Pressure Included
Authors: Civan F. , Donaldson E. C.
Published: December 2007

A semianalytic method for calculation of relative permeabilities from unsteady-state displacement data is developed. The method is based on the simultaneous solution of the fractional-flow equation and an integro-differential equation, derived from the material-balance and Darcy equations for immiscible displacement of two incompressible phases, including the capillary pressure by use of various volumetric relationships. This method for calculating two-phase relative permeabilities from unsteady-state displacement data is not restricted to the high-flow-rate experimental conditions used to overcome capillary end effects. Removal of this restriction allows the analysis of low-permeability cores with water and oil where the flow rates are low and capillary end effects are important. Our method allows direct calculation from the experimental data without intermediate interpretations of graphs.
Suspended Solids Specifications for Water Injection From Coreflood Tests
Authors: Eylander J. G. R.
Published: December 2007

A method based on the results of laboratory coreflood tests is proposed for predicting the injectivity decline rate of water injectors. The aim of this method is to provide design specifications for water treatment and injection facilities and procedures with which well injectivity behavior can be analyzed. To illustrate the results that can be obtained with the proposed method, data from coreflood tests are used to construct injectivity-decline-rate curves for an arbitrary injection well.
A Solvent Extraction Approach to Oil-Recovery Calculations From Laboratory Displacement Tests
Authors: Mezzomo R. F. , DeHolleben C. R. C. , Ferreira P. A.
Published: December 2007

An experimental method is proposed for quantification of oil in effluent samples from displacement tests with liquids. On a mass basis, this new procedure is offered as an alternative to the classic volumetric approach.

A known amount of a suitable organic solvent with good selective solubility and density contrast relative to the oil phase is thoroughly mixed with the effluent sample. After centrifugation, the oil/solvent mixture is analyzed for density. Subsequently, the oil mass fraction in the pseudobinary mixture (oil/solvent) is obtained through a previously determined correlation of this parameter vs. density. With these data—amount of solvent and oil mass fraction—plus the definition of the latter in a binary mixture, one arrives at the actual mass of oil in the effluent sample.

The method is applied to a crude oil from Miranga field in the Reconcavo basin (northeastern Brazil). Accuracy is thoroughly analyzed and compared with that of the volumetric approach. The method is also tested under such severe conditions as emulsified oil production. Finally, recommendations are made to implement the method in continuous oil-recovery monitoring, which would be a major step in the full automation of laboratory displacement tests.
The Kern River Horizontal-Well Steam Pilot
Authors: Dietrich J. K.
Published: December 2007

Sluggish oil response in the Kern River horizontal-well steam pilot was caused by placement of the wells in a reservoir environment unfavorable for application of either conventional oil recovery processes or novel oil-mining techniques. Encouraging pilot operational experience and the tremendous potential for improved ultimate oil recovery shown by preliminary simulations suggest that future pilot testing of horizontal-well steam technology is warranted in a more favorable environment.
Platform-Well Tieback Procedures at Island Esther
Authors: Jackson Elizabeth M.
Published: December 2007

On March 2, 1983, Island Esther, a man-made producing island located 1 xh miles [2.4 km] offshore southern California, was destroyed by a severe winter storm. The 90 completed wells survived the storm, but some were badly damaged. In 1985, a platform was erected over these wells, and work to repair the wells began. This paper discusses the methods and equipment used for that operation.
Mechanisms Controlling Fracture-Height Growth in Layered Media
Authors: Ben Naceur Kamel , Touboul Eric
Published: December 2007

This paper considers the mechanisms that affect the lateral and vertical extension of a hydraulically induced fracture. These include natural mechanisms—such as contrasts in stresses, moduli, toughness, and leakoff—and those induced by leakoff and fluid heterogeneities. Treatment trends during the injection and closure are analyzed with a state-of-the-art 3D fracture model. The effect of the vertical fracture penetration on conductivity and water coning and the parameters influencing them are then quantified.
Calculation of the Leak Location in an Aquifer Gas Storage Field
Authors: Burnett Peter G.
Published: December 2007

A leak location method for aquifer gas storage fields utilizing nonsteady flow calculations is presented. The calculation method uses pressure responses in observation wells completed in a permeable zone in or above the caprock overlying a gas storage reservoir to locate leakage which exists in a single area. The leakage considered is localized - different from the leaky aquifer case which is well known to ground water hydrologists. Field data from an operating gas storage field where gas leakage exists are used to calculate location of the leakage. The location is determined graphically using water level changes in three observation wells. The leak location is calculated to be at distances from the observation wells proportional to the square roots of the times of equal pressure responses at the wells. No absolute values of porosity, permeability, sand thickness or composite water and rock compressibility are required in the graphical solution. The leak location method presented is generally restricted to gas storages which have single-point leaks. However, the method is also applicable in cases where all observation wells are relatively close to one leak, with distances from other possible leaks too far, or other leaks too small, to affect appreciably the water level responses of the observation wells.

Introduction

In underground gas storage operations leakage from the storage reservoir to higher porous formations sometimes occurs through fractures in the caprock, behind the casings of improperly cemented wells or through improperly plugged abandoned wells. If the leakage rate is too great, the storage field may be uneconomical to operate. Sometimes it is feasible to collect gas from wells drilled to the higher formations for reinjection into the storage reservoir. Nevertheless, leakage is an economic burden to the storage operation, and gas injection pressures and corresponding injection rates must be limited to control the leakage rate. Accordingly, it is highly desirable to determine the nature and location of the leakage and to correct it if possible. In the storage field discussed in this article, tracer tests were conducted which indicated that major leakage was occurring in the southern end. Three wells were drilled almost through the caprock surrounding the indicated general area of leakage, and an attempt was made to hydraulically seal off the leak by injecting water through a porous sand stringer in the caprock. Water injection proved unsuccessful in sealing the leak, probably because permeability of the sand stringer was too low to permit injection of water at sufficiently high rates. Following the attempt to seal the leak hydraulically, water levels of the three wells were measured continuously and calculations were made from data obtained to try to determine location of the leak. The calculation method developed considers lateral flow in a permeable sand within the caprock.
Electric-Submersible-Pumping Success in the Beatrice Field, North Sea
Authors: Kilvington Lindsay J. , Thomson Jack Y. , Brown Julien K.
Published: December 2007

When the Beatrice field came into production in Sept. 1981, it was the first North Sea offshore oil field to depend from the outset on artificial lift to maintain production. In view of the low GOR of Beatrice crude, the use of electrical submersible pumps (ESP's) was the only feasible option. Maximization of the operating life of the downhole pump was obviously critical to the economic viability of the project.

This paper describes how the ESP performance at Beatrice has been progressively improved through diligent analysis of completion- performance data and failed equipment. The results have led to the optimization of completion design and the development of new and improvement of existing mechanical and electrical components.
On-Site Diagnosis of Cement Job Problems: The Concept of Job Signatures
Authors: Beirute R. M.
Published: December 2007

Since the introduction of free-fall models for primary cementing, several companies have been monitoring cementing operations by continually measuring the rate of returns, the rate of pumping, the density of the fluids pumped, the density of the fluids returned to the surface, and the surface pressure.' Measured values of surface pressure and rate of returns have been compared to predicted values obtained with cementing simulators. 1–7 Discrepancies between measured and simulated behaviors that cannot be explained as normal simulation and job measurement limitations are attributed to problems that develop during the cementing operation. Although problems have been detected by this approach, in some cases it has not been possible to ascertain the exact cause of the misbehavior. Therefore, proper and timely corrective adjustments have not always been made during the job.

To improve our ability to diagnose cement job problems while the cement job is in progress, we investigated six potential job problems with a cement job simulator that includes free fall. The job problems were channeling, unsuspected (unmeasured) washout, lost circulation, influx, flow restrictions, and slurry dehydration. Representative graphs show the behavior trends for each of the six potential cement job problems. The graphs show the normal (without trouble) behavior and the departure from the norm for the problem situation. Lists of generalized "job signatures" for each case are also given. Characteristics that are considered the main indicators of each job problem are highlighted. Three field cases illustrate how the concept of job signatures can be used effectively to assist in detecting potential job problems during the actual job.
A New Calcium-Tolerant Polymer Helps To Improve Drilling-Mud Performance and To Reduce Costs
Authors: Ujma K.-H. W. , Plank J. P.
Published: December 2007

Drilling fluids suitable for German Zechstein formation wells require fluid-loss polymers that tolerate up to 140,000 ppm of Ca/Mg and have temperature stabilities that exceed 350°F [177°C]. Problems experienced in previous wells with carboxymefhylcellulose (CMC) and poly anionic cellulose (PAC) are described. The use of starch with a new sulfonated polymer improved drilling mud performance and reduced costs. Major benefits come from a synergism of the new polymer with starch, resulting in a 50°F [25°C] gain in starch thermal stability. A similar temperature extension effect was found for such cellulose products as CMC or PAC after addition of the polymer. Field experience with the starch/new-polymer combination in Zechstein formation wells with depths to 15,750 ft [4800 m] shows excellent filtration control, hardness tolerance, and temperature stability for this system. A cost analysis confirms saving of 20 to 50% on fluid-loss polymer costs.
Mutual Solubility of Salts in Drilling and Completion Fluids
Authors: Kemp Nantelle P.
Published: December 2007

This paper describes models for predicting crystallization temperatures for pure- and mixed-salt brines. The models can be used to determine the solubility behavior of salt-containing fluids. Model predictions are compared to published mixing tables for heavy-brine completion fluids and to crystallization temperatures measured in the laboratory. Examples show how the models were used to formulate brine muds and to predict how much additional salt could be added to a produced brine mud to increase mud density without producing excess solids.
Method for Fracture-Gradient Prediction for Vertical and Inclined Boreholes
Authors: Aadnoy B. S. , Larsen K.
Published: December 2007

A new method for the prediction of fracture gradients in deeper wells has been developed. The method is based on the principles of mechanics but uses a correlation method in the application of field data. The new, improved method (1) gives both leakoff and lost-circulation pressures; (2) works for vertical and inclined boreholes; and (3) identifies lithological effects. The result is given as a simple equation where only well depth, pore pressure, borehole angle, and lithology are needed to predict the fracture pressure. Because borehole inclination is included, the method can be used during both production and vertical-well drilling. The method was applied in a field study offshore Norway. The results show a remarkably good correlation with field observations.
Using Oligomeric Surfactants To Improve Oil Recovery
Authors: Chou S. I. , Bae J. H.
Published: December 2007

Oligomeric surfactants are a unique class of surfactants that differ from conventional surfactants in their molecular structures. The hydrophilic portion of conventional surfactant molecules is usually smaller than their hydrophobic portion. For oligomeric surfactants, however, several polar and ionic functional groups, distributed along a hydrocarbon chain, form the hydrophilic part of the molecule. In addition, the hydrophilic part has a size comparable with or greater than the hydrophobic counterpart.

A number of surfactant/alcohol/oil/brine systems were investigated to evaluate the efficacy of oligomeric surfactants as cosurfactants in surfactant formulations. When used at a concentration of about 110 of the active surfactants, the resultant formulation exhibited higher solubilization capacity, lower interfacial tension (IFT), somewhat higher optimal salinity, higher salt tolerance, higher viscosity, and lower adsorption loss. These benefits may improve the economics of the surfactant flooding process and broaden its application range.

The mechanisms by which oligomeric surfactants affect the properties of surfactant formulations were investigated. Surface tension and potentiometric measurements showed that they formed mixed micelles with other surfactants and that they bound with divalent cations. These interactions lowered the activity coefficients of surfactants and counter-ions, thereby increasing the salt tolerance of the surfactant formulation while lowering the adsorption of surfactants on rock surfaces.

Oligomeric surfactants may also be used at low concentrations to improve waterflood performance in oil-wet reservoirs. Oil recovery in preferentially oil-wet Berea cores was significantly increased by use of a low-concentration surfactant slug. The higher oil recovery resulted from alteration of the rock wettability.
Steam-Foam Pilot Project in Dome-Tumbador, Midway-Sunset Field
Authors: Mohammadi S. S. , Van Slyke D. C. , Ganong B. L.
Published: December 2007

This paper describes a steam-foam pilot project in the Potter sand, Midway-Sunset field. The pilot consists of four inverted five-spot patterns with a confined producer covering 5.2 acres [2.1 ha]. Steam foam was generated by continuous injection of steam with NaCl, alpha olefin sodium sulfonate, and nitrogen. Production and subsurface data, obtained from two observation wells, were used as monitoring tools in the pilot. Overall, during the first 2 years of foam injection, 207,000 bbl [32 900 m3] of incremental oil was produced.
A Comprehensive Simulation Study of Steamflooding Light-Oil Reservoirs After Waterflood
Authors: Chu Chieh
Published: December 2007

Steamflooding, the most successful among enhanced recovery methods, has been applied mainly to heavy-oil reservoirs. This paper presents a comprehensive simulation study on the use of steamflooding after waterflood in light-oil reservoirs. Some important observations are made on this new application of the process. Guidelines are developed not only for selecting reservoir candidates for steamflooding, but also for designing and operating steamfloods in watered-out reservoirs. Relative importance of key mechanisms to oil recovery is also discussed.

Introduction

The use of steamflooding as a tertiary recovery method for light-oil reservoirs after waterflood has been of interest in recent years. Although steamflooding applied to heavy-oil reservoirs has been a fully proven method, the technology of applying it to light-oil reservoirs, especially those that have been watered out, is still in its infancy. This paper will answer the following questions that remain about steamflooding.Can watered-out light-oil reservoirs perform as well as heavy-oil reservoirs under steamflooding?What kind of reservoirs will be suitable for steamflooding after waterflood?How would one design and operate a steamflood once a reservoir is chosen?What are the main recovery mechanisms in this process?

Several authors have made simulation studies on steamflooding light-oil reservoirs. Aydellote and Ramesh studied steamflooding economics with variations in oil composition, permeability, depth, pattern type, well spacing, and steam injection rate. A uniform fluid saturation was used at the start of the steamflood. Hanzlik improved on this work by preceding the steamflood with a waterflood that generates a nonuniform fluid saturation before steamflood starts. Both waterflood and steamflood were considered to take place in the same 5-acre [2.0-ha] five-spot patterns. He studied the effects of oil composition, reservoir thickness, and steamflood timing on steamflood performance. Hongs studied steamflooding the light-oil reservoir at Buena Vista field, CA, using a uniform fluid saturation at the start.

This work starts with a 40-acre [16.2-ha] waterflood that is later converted to steamfloods with smaller patterns. A three-dimensional multiphase thermal recovery simulator with nine-point finite-difference formulation was used so that the grid orientation effect was greatly reduced in the simulation of steamfloods in five- and nine-spot patterns. A large number of reservoir oil and rock properties and also a large number of steamflood design and operating variables were considered. The following were developed: general observations on the process, guidelines for selecting candidates for steamflooding after waterflood, guidelines for designing and operating steamfloods, and relative importance of the various key mechanisms to oil recovery.
Rock Mechanical Analysis of North Sea Reservoir Formations
Authors: Holt R. M. , Ingsøy P. , Mikkelsen M.
Published: December 2007

Core material from a North Sea reservoir has been investigated for strength and elastic properties in triaxial tests. The material behaves nonlinearly elastically, and the rock strength correlates with the static shear modulus in a data range previously little investigated. Dynamic elastic properties obtained by downhole measurements with full-waveform logs are compared with the laboratory-derived strength. Laboratory acoustic measurements show that the sonic velocities are strongly stress dependent, which is closely related to the previously mentioned elastic nonlinearity. Also, dynamic elastic moduli are found to exceed the static moduli considerably, which has to be taken into account when evaluating mechanical properties from logs. Because of the nonhydrostatic stress state downhole or in laboratory triaxial tests, an acoustic anisotropy is induced. On unconfined core materials, the pronounced observed acoustic anisotropy may, to a large extent, be caused by stress relief during and after coring. The possibilities of using this effect in in-situ stress determination are elucidated. Finally, the mechanical-properties logging practice commonly adopted is compared with experimental data, showing that the log interpretation approach must be modified to account for the data.