bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Engineering Analysis of Microbial Enhanced Oil Recovery
Authors: Bryant Steven L. , Lockhart Thomas P.
Published: December 2007

We assess processes for enhancing oil recovery by means of microbes (MEOR) from the perspectives of reservoir and reaction engineering. In this work, MEOR refers to recovering incremental oil by increasing displacement and/or volumetric efficiency; it does not include well stimulation treatments. MEOR processes address the same physical parameters as chemical enhanced oil recovery (EOR) processes; hence, they are subject to the same technical difficulties: identifying and locating the target oil and retention, dissipation, and consumption of chemicals in the formation. The essential difference between MEOR and chemical EOR resides in the method of introducing the recovery-enhancing chemicals into the reservoir.

Although quantitative measures of microbial performance (reaction rates, stoichiometry, required product concentrations) are lacking, it is possible to demonstrate quantitative relationships between microbial performance, reservoir characteristics, and operating conditions (well spacing, injection rates, residual oil saturation). These relationships are the focus of this paper. From them, we conclude that MEOR is potentially a "high risk, high reward" process, depending on whether it can use residual oil as an in-situ carbon source for the production of recovery-enhancing chemicals. The reward in this case is that the difficulty and the logistical costs of implementing the process would approach those of implementing a waterflood. The risk is associated with the many and severe performance constraints that a microbial system would have to satisfy to take advantage of an in-situ carbon source. The current state of knowledge fails to provide satisfactory evidence that existing systems can meet the constraints identified in this study; thus, an ambitious program of research and development would be required to determine MEOR feasibility.
Influence of Differential Displacement in Invaded Oil and Gas Sands on the Induction Log
Authors: DeWitte A.J.
Published: December 2007

It has been observed that upon invasion of a sand containing oil or gas and connate water by mud filtrate the hydrocarbons are more rapidly flushed by the filtrate than is the connate water. In time, it appears that the following displacement pattern emerges: oil (or gas) is being swept ahead by connate water which, in turn, is pushed by invading fluid. Eventually the connate water may have "banked up" sufficiently to form a zone of appreciable thickness leading the invading front. In the extreme case, Fig. 1 shows how the situation will develop:

Immediately adjacent to the borehole (radius r) there is a zone, the invaded zone proper, where the connate water has been flushed out completely and which contains only residual oil or gas and mud filtrate. This zone (extending out to a radius ri) grades more or less abruptly into the next (thickness ?,), which contains only residual hydrocarbon and connate water. Beyond it, again more or less sharply bounded, extends the virgin formation with the original interstitial water saturation Sw. The various saturations are indicated in Fig. 1.

The three zones generally will be marked by resistivity contrasts owing to their different fluid contents. As the connate water is usually more saline than the invading fluid, the second zone having a high connate water saturation forms a concentric cylindrical ring or annulus of low resistivity Rl around the borehole. It will be referred to as the "low zone." Fig. 1 shows schematically the resistivity profile.

It is clear that the phenomenon of a low zone could not occur in invaded water sands. The presence of a low zone, therefore, would be a qualitative indication of a hydrocarbon-bearing formation. Granted that the phenomenon is real, if it were pronounced enough to be detected, one might thereby have a means of locating oil or gas in the ground. This is the aim of the "displacement logging" method. In any case, the presence of a low resistivity zone will affect the reading of electric logs. Using conventional log interpretation techniques, one must be aware of this and, if necessary, correct for it.
Oil and Gas Separation IS a Science
Authors: Worley M. Steve , Laurence Lawton L.
Published: December 2007

Introduction

Some oil and gas separations are simple while others are very complex. The oldest forms of separation were manual operations. Observation of physical differences in the components of the mixture to be separated, (color, size, shape, etc.) formed the basis for the action. The actual Separation was then accomplished by applying some force or influence to get the "sheep" into one pen and the "goats" in another.

All separations rely on some physical or chemical difference in the things to be separated. The type and amount of force or influence necessary to effect the separation is determined by these differences. Application of known physical laws of nature are very helpful. Where the known physical laws are inadequate, experience is necessary, often resulting in relatively inefficient cut and try methods with many tests. When the conditions of the separation process change, it is often necessary to drastically change the force or influence causing separation in order to maintain a high efficiency.

Oilfield lease separations vary from removing slugs of oil from gas to dehydration and hydrocarbon fractionation. However, this paper will be limited to a discussion of the mechanical separation of gases and liquids. No matter what the cause of gases and liquids occurring together, their separation cannot ever be complete. The design of separation equipment then becomes a question of balancing cost with desirable or necessary efficiency.

General Description of Types

Vertical

The most general classification of separators in the oilfield regards their shape. The first and still most popular type of separator consists of vertical cylinder with appropriate internals. The inlet is near the center of the vessel with the gas outlet near the top and the liquid outlet near the bottom. It is a very versatile separator due to its flexibility in operation.

Horizontal

Larger gas capacities can be handled in a horizontal cylinder than in the same diameter vertical cylinder. However, higher gas throughput usually leaves less space for liquid surge and for the accumulation of mud, sand and paraffin. The application of this type separator is very satisfactory for known flowing conditions in a moderately clean well-stream.

Spherical

Recently spherical separators have gained considerable popularity. The shell consists of two hemispherical heads with appropriate internal construction. They have operating versatility comparable to the horizontal separator and are very compact and easily hooked up.
A Note on Transient Two-Phase Flow Calculations
Authors: Wallick G.C.
Published: December 2007

Introduction

Since the appearance of the paper, "Solution of the Equations of Unsteady State Two-Phase Flow in Oil Reservoirs," by W. J. West, W. W. Garvin, and J. W. Sheldon," a twofold investigation of this subject has been carried out. One objective of the investigation has been to determine the feasibility of solving such problems on a medium-size computer such as the Datatron, and the other objective has been to investigate the application of such calculations to experimental and theoretical petroleum reservoir research. In the first Datatron calculations, the fluid and rock properties published by West, et al, were used, together with the published equations describing the system. Details of the formulation not given in the original paper are discussed in the Appendix to this note. Reference should be made to the subject paper for the complete equations and definition of symbols.

An unexpected result of this investigation was the discovery that the linear solution published by West was in error. Thus, in addition to describing the Datatron solutions and to discussing certain numerical difficulties which will be encountered if one uses the published method of solution, the purpose of this note is to indicate the nature of this error.

Linear Flow

Since the linear case requires a minimum amount of scaling, a fixeddecimal point Datatron program was written for the one-dimensional flow problem and an attempt was made to duplicate the solution described by West.

As a check on the accuracy of the solution, the cumulative production at each time step was calculated using the two methods described in the Appendix. Satisfactory agreement was observed with the differences in these two values of the order of two parts in 50,000. It should be noted that the mass balance check as described is of questionable value, particularly with regard to the well pressure and saturation. This is especially true in the radial solution where pressure and saturation values near the well bore would make only a negligible contribution to the numerical integration.
Implementation of a Flux-Continuous Finite-Difference Method for Stratigraphic, Hexahedron Grids
Authors: Lee Seong H. , Tchelepi Hamdi A. , Jenny Patrick , DeChant Larry J.
Published: December 2007

In this paper we present a 3D flux-continuous finite-difference formulation designed for flow simulation of models with nonorthogonal hexahedron grids with general tensor permeability. Our development follows that of Aavatsmark et al.,1 but we do not operate in transformed space. The new 27-point discretization formula has been implemented in a finite-difference reservoir simulator. This stencil has many desirable properties, including collapsing into a consistent form in two dimensions. We demonstrate that there are many practical situations in which neglecting the influence of nonorthogonality and general tensors results in firstorder errors in flow predictions. A rigorous implementation for this 27-point difference operator as a control-volume finite-difference method determines the upwinding of convection terms associated with multiphase computations. Results and issues associated with implementation of this operator in a conventional finite-difference reservoir simulator are discussed. As an alternative to directly solving the linear matrix associated with the 27-point stencil of the flux-continuous operator, we examine iterative methods that split the matrix into a 7-point stencil part and a remainder. The 7-point stencil part is solved by a direct or iterative method, with the remainder part updated from the previous timestep or iteration. This split operator may permit retention of the linear solver for the standard 7-point formulation while retaining nonorthogonal grid and tensor information.
A Comprehensive, Practical Approach For Wellbore Instability Management
Authors: Chen X. , Tan C. P. , Haberfield C. M.
Published: December 2007

In the northwest shelf, a region of growing importance for oil and gas production in Australia, drilling delays and well suspension before reaching targets have occurred frequently because of wellbore instability. As a result, the economic benefits from new drilling technologies are significantly reduced because of high additional drilling costs. To improve drilling efficiency and minimize drilling costs, it is crucial to develop and apply a practical approach for optimizing wellbore instability management.

This paper initially presents guidelines, in the form of design charts, for efficient wellbore stability analysis and wellbore profile design. A comprehensive, practical approach that uses the design charts for wellbore profile design is described subsequently. The application of the design charts is demonstrated through field case studies for a range of in-situ stress regimes.
Generalized Pressure-Volume-Temperature Correlations
Authors: Glaso Oistein
Published: December 2007

Empirical equations for estimating saturation pressure, oil formation volume factor (FVF) at saturation pressure, and two-phase FVF were derived as a function of reservoir temperature, total surface-gas gravity, producing GOR, and stock-tank oil gravity. These equations should be producing GOR, and stock-tank oil gravity. These equations should be valid for all types of oil/gas mixtures after correcting for nonhydrocarbons in surface gases and paraffinicity of oil.

Introduction

Pressure-volume-temperature (PVT) correlations are Pressure-volume-temperature (PVT) correlations are important tools in reservoir technology. These measurements form the basis for estimating the amount of oil in the reservoir, production capacity, and variations in produced gas/oil ratios during the reservoir's production life. PVT relations also are a requirement for calculating the recovery efficiency of a reservoir. Especially during the prospection phase, when only produced fluid properties are available from flowing tests, one can resort to empirically derived PVT relations. It is, of course, of great importance PVT relations. It is, of course, of great importance that such estimations be as accurate as possible. From PVT correlations published until now, Standing's work is perhaps the most widely used. His correlations were developed for California oils and make no corrections for oil type or nonhydrocarbon content. Other PVT relations developed for oils from other parts of the world, based on Standing's work, yield "best-fit lines" ordinarily parallel-shifted. Their differences can be understood from two factors not included in Standing's original correlations:crude oils from other regions have different paraffinicity - i.e., they contain varying amounts of paraffinic oil components (saturated hydrocarbons in open chains), andthe surface gases from some reservoirs contain relatively large amounts of nonhydrocarbons (CO2, N2, and H2S).

By considering the variation in these parameters, this paper develops generalized PVT correlations:

(1)

(2)

(3)

These equations were derived from laboratory data, exclusively sampling North Sea oils. However, they should be valid for all types of gas/oil mixtures after correcting for nonhydrocarbons (CO2, N2, and H2S) in the surface gases and paraffinicity of the oil as defined by the Kuop factor.

Procedure Procedure PVT Measurements PVT Measurements Six reservoirs fluid samples were made from two North Sea separator liquid and gas samples. These reservoir samples were labeled A1, B1, and C1 and A2, B2, and C2. Fig. 1 shows the experimental procedure used in the PVT analysis. procedure used in the PVT analysis. JPT

P. 785
Gas Injection Performance Review of the LL-370 Reservoir in the Bolivar Coastal Field, Venezuela
Authors: Edison T.O.
Published: December 2007

The Conservation Plant Tia Juana No.1 began pressure maintenance operations of the LL–370 area of the Bolivar Coastal field in Oct., 1954. Gas is being returned to the B–6 Eocene sandstone via seven injection wells.

During the first two years of operations, the average injection rate has been 133.9 MMcf/D. This represents a small excess of gas injected over hydrocarbon volume withdrawals. In the third quarter of 1956, average production was 77,583 BOPD, with a producing gas-oil ratio of 876 cu ft/bbl. Fifty-nine wells were classified as producers.

Production characteristics of the LL–370 area under pressure maintenance have been very satisfactory and superior to predicted behavior. There has been no evidence of excessive gas channelling. The vertical segregation of oil and gas in the reservoir continues to play an important part in the production mechanism. As a result, required high-gas shutoffs in up dip areas continue to be successful with the isolation of upper high-gas saturated zones by squeeze cementing and the return of the lower portion of the sandstone to low gas-oil ratio production. The average reservoir production decline is nil, with the production decline of individual wells balanced by production increases in others.

Not only will this project result in a much greater recovery of oil from the reservoir, but also a huge quantity of gas is being conserved for the future.

Geology and General Reservoir Characteristics

The LL–370 area is located in Lake Maracaibo 7 miles from the community of Tia Juana which is on the northeast shoreline of the lake. The oil-bearing formation consists of a truncated monocline of Eocene sandstone called the B–6. The total surface area covers 11,048 acres and is subdivided into four reservoirs by faults, which are only partial pressure barriers. The area is bounded by major faulting to the northeast and southwest, the Miocene-Eocene unconformity to the west at the top of the formation, and a water leg to the southeast. Additional Eocene productive units overlie and underlie the B–6, but these are isolated by extensive shale barriers and only local communication probably exists.
Chemical Analyses of Brines From Four Imperial Valley, CA, Geothermal Wells
Authors: Needham P. B. , Riley W. D. , Conner G. R. , Murphy A. P.
Published: December 2007

A brief report is given of studies of brine chemistry on both high- and low-salinity geothermal fields in support of a field corrosion testing program being conducted by the USBM in the Imperial Valley, CA. Specific results are reported for four geothermal wells: Mesa 6-1, Mesa 6-2, Magmamax No. 1, and Woolsey No. 1. These results demonstrate the necessity for careful reporting of the specific well operating conditions and brine sampling techniques under which the brine analyses were obtained. In particular, information related to recent well shut-in periods, total stabilization time, recent production engineering, brine flow rate from the well, and identification of nonturbulent-structure brine-flow configurations must be documented carefully with any reported analyses.
The Development and Application of a Novel Scale Inhibitor Deployment System
Authors: Collins I. R. , Jordan M. M. , Taylor S. E.
Published: December 2007

Water-in-oil emulsions have been developed that have been shown to be a credible means of deploying scale inhibitors in a nonaqueous medium. Furthermore, the use of slowly degrading emulsion systems provides a means of trapping the scale inhibitor within porous media and allowing the subsequent controlled release of the chemical. This has been demonstrated with sandpack and core-flood experiments in which the inhibitor's lifetime, as measured by pore volumes of brine eluted to a given inhibitor concentration, has been extended by up to (and possibly beyond) four times compared with the base-case, nonemulsified product. No permeability damage has been observed for the emulsion systems. The use of emulsion droplets to provide chemical reservoirs within the formation also considerably reduces the nonretained chemical waste observed with conventional squeeze treatments. The nonaqueous nature of the emulsion system allows the potential ingress of the scale inhibitor into parts of the reservoir normally denied access to an aqueous-based formulation, so it can improve contact between the scale inhibitor and the reservoir fluids on production. Furthermore, the whole treatment can be nonaqueous, allowing oil continuity to be maintained during the treatment and affording rapid well cleanup post-treatment. The efficacy of the emulsion system is illustrated with the results of a successful field trial performed on the Forties field in the U.K. sector of the North Sea.
Investigation of Sulfide Scavengers in Well-Acidizing Fluids
Authors: Nasr-El-Din H. A. , Al-Humaidan A. Y. , Fadhel B. A. , Frenier W. W. , Hill D. G.
Published: December 2007

This paper describes the development of acidizing systems that use several different aldehyde-based sulfide-suppression chemicals in conjunction with new acid-corrosion inhibitors. Specific combinations of these chemicals have allowed the acid to dissolve the FeS and suppress the formation of H2S, yet still enable acid inhibition to industry corrosion standards.

Experimental results were compared with previously published data.1 Field acid treatments were accomplished successfully, and they resulted in large increases in gas production.

The new chemicals and procedures will allow the operators to safely remove large amounts of fouling deposits while controlling the toxic and corrosive effects of H2S much more effectively than with previously used products.
New Well-Testing Methods for Rod-Pumping Oil Wells—Case Studies
Authors: Guoynes John , Azari Mehdi , Gillstrom Robert , Friend Bret , Fairbanks Mike
Published: December 2007

A new well-testing method that provides high-resolution bottom-hole pressure (BHP) measurement has been developed for use with rod-pumping oilwell completions. This new well-testing technique is conducted by running a high-resolution downhole pressure gauge in a specially designed carrier assembly with the downhole pump. The gauge assembly is run on the rod string without pulling the completion packers or tubulars. With the new method, a down-hole pressure system is in place while the well is flowing during the entire well test. High-resolution downhole pressure data can then be recorded during all flow and shut-in periods of the well test, providing more accurate pressure data and enhanced capability for reservoir analysis.

Traditional techniques use wireline-conveyed pressure gauges, tubing-conveyed pressure-recording devices, and surface pressure-monitoring systems with an advanced fluid-level measurement to record data from pumping well completions. These methods are limited in their ability to provide accurate test results when low-pressure conditions prevail. The new method allows operators of low-pressure oilwell completions to use advanced well-testanalysis software to analyze actual pressure data to obtain reservoir properties and quantify skin damage. Data can be acquired from many types of rod-pump completions, including wells with downhole gas separators. Excellent pressure resolution has been obtained from this new testing technique with either of two downhole assembly designs depending upon the completion configuration.

The results and the ensuing well-test analyses in several pilot pumping wells will illustrate that the new process permits more flexibility in well testing and allows for greater accuracy and better interpretation of data in low-pressure rod-pumping oil wells.
Instrumentation for Simplified Commingling and Well-Testing Operations
Authors: Kite George
Published: December 2007

This paper discusses the theory, operation and practical application of a low-cost, field-proven instrumentation system which saves money and greatly simplifies lease-commingling and well-testing operations by providing an accurate, direct digital readout of the volume of net clean oil in oil-water streams containing up to 100 per cent water.

Introduction

Lease-commingling and well-testing operations usually require a measurement of the amount of "net clean oil" in an emulsion stream produced by a well or group of wells. Conventional methods of net oil metering require physical separation or treating and subsequent metering of oil and water volumes. Various arrangements of three-phase separators, gas-fired emulsion treaters, fluid meters and samplers are in wide use but are often unnecessarily expensive and complicated; frequently they leave much to be desired insofar as accuracy, operator convenience and adaptability to automation are concerned. The instrumentation system discussed automatically and continuously meters and monitors an oil-water stream containing pure oil, pure water, emulsion, or any combination thereof, and, without requiring physical treating or separation, provides an accurate digital readout of net clean oil volume, directly in barrels. No calculations, conversion factors, or interpretations are required; data are presented instantly, continuously and cumulatively in the most usable form. In addition, electrical digital signals for remote counting and an electrical analog signal for remote percentage water indication or recording are available at the computer terminal block.

Description of Equipment

The system uses an ordinary positive-displacement fluid meter, a wide-range electronic capacitance-measuring instrument, and an electro-mechanical computer. The PD meter measures total fluid volume and supplies a rotational, mechanical input to the computer. The capacitance instrument electronically determines the instantaneous percentage of water in the fluid stream. The computer subtracts the water volume from the total fluid volume and provides an output of the integrated volume of net clean oil. Fig. 1-A shows a typical skid-mounted net oil measuring assembly, consisting of a fluid strainer, a PD meter, a capacitance probe, the computer assembly and a diaphragm-operated fluid dump valve. This skid assembly would be installed downstream of a conventional fluid-gas separator, which is required only to prevent gas from damaging the PD meter. In operation all separator liquids would be discharged from the separator outlet through the skid assembly. Liquid dumping would be controlled by the pneumatic, snap-acting level control on the separator and the diaphragm-operated dump valve on the skid assembly. Two counters in the computer panel would then provide a direct readout of barrels of total fluid and barrels of net clean oil.

JPT

P. 732ˆ
Relative Permeability Modification in Gas/Liquid Systems Through Wettability Alteration to Intermediate Gas Wetting
Authors: Tang Guo-Qing , Firoozabadi Abbas
Published: December 2007

The wettability of Berea and chalk samples for gas/oil and gas/ water fluids were altered from strong liquid wetting to intermediate gas wetting. Two polymers, FC-722 and FC-759, were used to alter the wettability. FC-759 is soluble in water and 120 as expensive as FC-722. Gas and liquid relative permeabilities were measured before and after wettability alteration. The results demonstrated a significant increase in liquid-phase relative permeability. Gas-phase relative permeability for a fixed saturation may increase or decrease; however, because of the very high liquid mobility and reduced liquid saturation, the gas mobility also increased for a fixed pressure drop.

A number of liquid injectivity tests were also carried out. The results revealed that the liquid-phase mobility could increase significantly when the wettability of rocks was altered from strong liquid wetting to intermediate gas wetting. All the results show clearly that the application of wettability alteration to intermediate gas wetting may significantly increase deliverability in gas condensate reservoirs.
The Integration of Capillary Pressures and Pickett Plots for Determination of Flow Units and Reservoir Containers
Authors: Aguilera R. , Aguilera M. S.
Published: December 2007

This paper shows how to construct lines of constant capillary pressure, process speed, pore-throat aperture, and height above the free water table on a Pickett plot. The integration of these properties allows the determination of flow units and reservoir containers and illustrates the important link between geology, petro-physics, and reservoir engineering.

The concept of flow (or hydraulic) units and reservoir containers has been used in the oil industry with a good deal of success during the past few years. The process or delivery speed k/ϕ can be used in many instances to define a flow unit. Correlation of flow units between wells helps to establish reservoir containers and forecast reservoir performance.

We show that a Pickett crossplot of effective porosity vs. true resistivity should result in parallel straight lines for intervals with constant process speed k/ϕ. The slope of the straight lines is related to the porosity exponent m, the water-saturation exponent n, and constants in the absolute permeability equation. From the straight lines, it is possible to determine capillary pressures and pore-throat apertures directly for each flow unit at any water saturation. Pore throats at 65% water saturation compare very well with Winland r35 values. The method has not been published previously in the literature.

Building lines of constant k/ϕ allows the display of complete capillary pressure curves on the Pickett plot, including regions that are and are not at irreducible water saturation. Previous empirical methods for determining the absolute permeability of a given interval assume that the water saturation is at irreducible conditions. This paper presents a technique that allows us to estimate absolute permeability even if the interval contains moveable water.

The use of this technique is illustrated with previously published data from the Morrow sandstone in the Sorrento field of southeastern Colorado and carbonates from the Mission Canyon formation in the Little Knife field of North Dakota. We conclude that flow units can be determined reliably from the integration within one single log-log graph of Pickett plots, capillary pressures, pore-throat apertures, and Winland r35 values.
Heat-Transfer Models for Mitigating Wellbore Solids Deposition
Authors: Kabir C.S. , Hasan A.R. , Lin D. , Wang X.
Published: December 2007

Tubular flow restrictions caused by solids deposition create serious oilfield problems. Solids normally originate from either asphaltic or paraffinic oil. Hydrates add another dimension to the problem when water production begins. Most solutions center on the use of aromatic solvents for asphaltenes and chemicals or heating for paraffins.

In this study, we seek preventive measures to minimize solids deposition by altering characteristics of fluid flow in the wellbore. The knowledge of fluid thermodynamic behavior, and the application of fluid principles and heat flows, constitute the essence of our approach. Specifically, we present a steady-state model that allows computation of wellbore pressure and temperature profiles for a hot-circulating fluid in the case of parrafins. The same model is used to study the p-T behavior of asphaltic oil while circulating a cold fluid.

A fluid-temperature model is also presented when intermittent or continuous injection of solvent is sought through a chemical-injection line. Both models are general in that flows in offshore wells can be handled rigorously.

Computational results show that preserving energy of paraffinic oil is feasible by circulating hot fluid in the annulus and/or using insulation, thereby keeping solids in solution. The use of an unsteady-state flow model sheds light on the time available for well intervention before the onset of deposition. Similarly, cooling of fluids may help produce asphaltic oils under favorable conditions.
Engineering Planning and Supervision of Directional Drilling Operations
Authors: Edison J.E.
Published: December 2007

For many years the planning and supervision of directional drilling operations have been more-or-less limited to those organizations and individuals specializing in directional work. Without attempting to minimize the importance of and necessity for these directional specialists, operating companies have become increasingly aware of the contributions which competent engineering planning and supervision can make toward a successful directional drilling campaign.

The part which such planning and supervision can play in directional operations is illustrated by a recent drilling campaign undertaken by Sun Oil Co. To test a Marginulina sand structure underlying a portion of the lower Texas Gulf Coast, three relatively large-displacement directional wells were drilled from Padre Island out under the Gulf of Mexico. While the hazards and limitations involved in drilling high-angle wells were recognized, the cost advantage of a successful directional campaign, as compared with other methods of drilling in the 20- to 40-ft waters, made the calculated risk well worth accepting.

Careful and detailed planning preceded the operation. Among the factors considered were:selection of directional drilling specialists,study of rig requirements and selection of contractor,target tolerance,kickoff depth,casing and hole-size program, anddrilling mud program.

With the exception of one short fishing operation, the directional operations progressed in a satisfactory and troublefree manner. On each of the wells approximately 9,000 ft of hole were drilled to secure horizontal displacements ranging from 3,900 to 4,500 ft at true vertical depths of 7,900 ft. Maximum angles ranged from 31 ½ to 43 ½. All holes bottomed well within target limits, and the drilling times, raging from 32 to 42 days, are considered quite good for this specialized operation. No difficulty was experienced with any of the casing or casing operations.

Average cost of the directional wells was $125,000; it is estimated that vertical wells drilled by platform and tender or drill barge would have cost a minimum of $300,000 and probably $500,000.

Sun's successful directional program may be attributed largely to the following factors, all of which enhance the chance for success on any directional program:careful planning; close, informed supervision, andadequate drilling rig and equipment; cooperative and experienced rig personnel; a competent and responsible directional specialist.
Analytical Modeling of Oil Recovery by Steam Injection: Part I – Upper Bounds
Authors: Yortsos Y. C. , Gavalas G. R.
Published: December 2007

This paper deals with the derivation of upper bounds for the growth of the steam zone in steam injection processes for one- or multidimensional reservoirs at constant or variable injection rates. The bounds are derived from the integral balances describing a reservoir of arbitrary geometry by introducing lower bounds for the heat losses to the surrounding area and the hot liquid zone. In this way, the effect of preheating in the hot liquid zone is estimated to determine the recovery efficiency of a steam drive.

The growth rate of a one-dimensional steam zone at variable injection rates is subject to two upper bounds resulting from the total thermal energy and the latent heat balances, respectively. Each of the bounds controls the rate of growth of the steam zone in a certain time interval, depending on the dominant mode of heat transfer in the hot liquid zone. At constant injection rates, the steam zone growth at large times is controlled by the bound based on the latent heat balance. This balance depends on a dimensionless parameter, F, defined as the ratio of the latent heat to the total heat injected. Based on the relative magnitude of F with respect to the critical value F = 2/π, the region of validity of the Marx-Langenheim solution is delineated on a Ts vs. fs diagram. The Marx-Langenheim solution is satisfactory at large times when F>2/π and becomes less satisfactory as F assumes smaller values.

Similar upper bounds are obtained for a two-dimensional steam drive (thin reservoirs). In three-dimensional reservoirs, on the other hand, bounds are derived only for a special form of displacement (separable front). These bounds depend on the geometric parameter κ that measures the extent of gravity override. By means of simple analytical models for the steam front shape, κ can be determined in terms of the physical variables of the process.
An Application of Cemented Resistivity Arrays To Monitor Waterflooding of the Mansfield Sandstone, Indiana, U.S.A.
Authors: Bryant I. D. , Chen M.-Y. , Raghuraman B. , Raw I. , Delhomme J.-P. , Chouzenoux C. , Pohl D. , Manin Y. , Rioufol E. , Oddie G. , Swager D. , Smith J.
Published: December 2007

In 1999, an oilfield experiment was initiated to test the application of electrical measurement technologies to permanent reservoir monitoring. The principal objective of the experiment was to demonstrate the feasibility of monitoring water movement between an injection and an observation well. This paper describes the interpretation of the data provided by the resistivity arrays and discusses the data quality and reliability of the measurements.

Two wells were drilled into the Mansfield sandstone reservoir in Indiana, U.S.A. The D-8 injector well was located in the center of four development wells. The OB-1 monitoring well was offset 233 ft to the southwest in a location midway between the D-8 injector and the No. 3 production well. The injector was instrumented with a 16-electrode resistivity array that was run on the outside of insulated casing and cemented into the annulus of the well. A similar array was cemented into the annulus of the monitoring well.

In March 1999, the D-8 well was perforated and acidized. A surface gauge was used to monitor injection rates and pressures. Initially, injection proceeded at a rate of approximately 20 B/D, increasing to 90 B/D after fracture stimulation. The D-8 array records responses to wellbore operations and injection. It clearly distinguishes the movement of the waterfront in different zones. The OB-1 electrical array clearly indicates early water breakthrough by means of an induced fracture. The data show good signal-to-noise ratio and high reciprocity.

The experiment has demonstrated the viability of using permanently installed resistivity arrays to monitor the movement of oil/ water contacts and salinity fronts that are some tens of feet away from the wellbore. Results demonstrate the feasibility of using such arrays to monitor oil/water contact movements remote from injection, monitoring, and production wells.
Modeling of the Acidizing Process in Naturally Fractured Carbonates
Authors: Dong C. , Zhu D. , Hill A. D.
Published: December 2007

When a naturally fractured carbonate formation is treated with acid at pressures below the fracturing pressure, the acidizing process will likely be different from either a matrix treatment or an acid fracturing treatment. Our previous experimental study shows three kinds of acid etching patterns after acidizing naturally fractured carbonates, and it also illustrates their relationships with the fracture properties and acidizing conditions. Based on the experimental observations, a mathematical model of acidizing naturally fractured carbonates has been developed. The model includes bulk solution transport, acid transport and reaction, and the change of fracture width by acid dissolution. A new approach was used to treat leakoff acid and acid-rock reactions at the fracture walls. The new acidizing model for numerically generated rough-surfaced fractures predicts the same kinds of acid etching patterns and the same relationships between acid etching patterns and the fracture width, surface roughness, and leakoff rate as observed in experiments.
Lateral Buckling of Pipe With Connectors in Curved Wellbores
Authors: Mitchell Robert F.
Published: December 2007

Connectors should clearly have an effect on pipe loading. For nonbuckled pipe, Lubinski analyzed the effect of connectors on pipe in tension in a curved borehole and Paslay and Cernocky extended this analysis to pipe in compression. Recently, helically buckled and laterally buckled pipes with connectors have been analyzed. In these papers, analytic solutions of the beam-column equations were developed in 3D, and critical loads were determined for buckling initiation. Conditions for positive contact forces were determined and compared to previous buckling criteria, such as Dawson-Paslay.

In this paper, the wellbore curvature effects studied by Lubin-ski, Paslay, and Cernocky are included in the buckling effects. The modifications necessary to analyze lateral buckling are made for a curved wellbore. The resulting model gives a buckling criterion similar to He and Kyllingstad's results for pipe without connectors. The buckling model is integrated with the Paslay-Cernocky analysis to resolve some of the odd bending-stress results developed by their model. Pipe deflections, contact loads, and bending stresses are determined with explicit formulas. Sag between connectors is calculated so that pipe contact with the wellbore between connectors can be determined. Conditions for positive contact forces are determined and compared to previous buckling criteria, such as Paslay-Dawson and He-Kyllingstad.

Applications include the analysis of bottomhole assemblies (BHAs), drillpipe, casing, and tubing. The solutions are simple formulas that are suitable for hand calculations.
A Simple Model To Predict Natural Gas Separation Efficiency in Pumped Wells
Authors: Harun A. F. , Prado M. G. , Serrano J. C. , Doty D. R.
Published: December 2007

A new mechanistic model to predict natural separation efficiency in vertical pumped wells has been developed. The model is based on the combined phase momentum equations and a general slip-closure relationship. New drag-coefficient correlations have been developed that correspond to bubbly (i.e., undistorted particle) and churn-turbulent flow regimes. The model indicates that natural separation efficiency depends strongly on geometry, void fraction, and in-situ gas flow rate.
An Alternative View of Filter-Cake Formation in Fractures Inspired by Cr(III)-Acetate-HPAM Gel Extrusion
Authors: Seright R. S.
Published: December 2007

A new model was developed to describe water leakoff from formed Cr(III)-acetate-HPAM gels during extrusion through fractures. This model is fundamentally different from the conventional filter-cake model used during hydraulic fracturing. Even so, it accurately predicted leakoff during extrusion of a guar-borate gel. Thus, the new model may be of interest in hydraulic fracturing. Contrary to the conventional one, the new model correctly predicted the occurrence of wormholes and stable pressure gradients during gel extrusion through fractures.
A Two-Scale Numerical Subgrid Technique for Waterflood Simulations
Authors: Arbogast Todd , Bryant Steven L.
Published: December 2007

We present a two-scale numerical subgrid technique for simulating waterflooding. Local subgrid computations are combined with a coarse-grid computation to provide a fine-scale resolution of the solution. We use porosity, relative and absolute permeabilities, the location of wells, and capillary pressure curves defined on the fine scale. No explicit macroscopic coefficients nor pseudofunctions result. The method is several times faster than solving the fine-scale problem directly, generally more robust, and yet achieves good results as it requires no ad hoc assumptions at the coarse scale and retains all the physics of the original multiphase flow equations.
Concentric Workover Operations in Deep Sour Wells
Authors: Fincher Norton E.
Published: December 2007

This paper describes an effort to reduce workover cost by applying concentric workover operations to deep sour wells. A medium-duty workover rig performed a variety of remedial procedures through the production tubing. Successful use of the concentric technique at great depths and in a hostile sour environment provides a valuable tool for recovery of additional oil and gas at lower cost.

Introduction

Exxon Co. U.S.A. operates more than 130 deep [15,500-ft (4724-m)] sour Smackover and Norphlet oil and gas wells in five fields in northwest Florida and south Alabama. Concentric workovers were performed in four of the fields (Jay/Little Escambia Creek, Big Escambia Creek, Blackjack Creek, and Flomaton); however, the program at Jay/Little Escambia Creek (LEC) field has been the largest and is the one discussed here. Conditions applying at Jay/LEC also apply in the other fields.Conventional workovers to recondition a well require a rig to remove the Christmas tree and pull the production tubing. At Jay/LEC this involves using drillpipe to mill out a permanent-type packer to perform the required remedial work. These conventional workovers cost between $700,000 and $1,000,000. In contrast, concentric workovers perform the required work by use of small work pipe run through the production tubing using a small rig or other hoisting unit. The cost of a concentric workover at Jay/LEC averages about $175,000 or approximately one-fourth the cost of a conventional workover.Concentric methods are not new. The techniques have been in use for about 25 years. Concentric workovers have been used at lesser depths to wash out obstructions, fish, acidize, squeeze cement, drill cement, consolidate sand, etc. The uniqueness of the work described in this paper is that the work was performed at greater-than-usual depths and in wells which produce with 10% hydrogen sulfide in the well fluids.

Objectives of Workover Program

Work is performed on producing wells and water-injection wells with the following objectives:to increase well producing capacity, capture additional reserves, and improve waterflood conformance by opening zones not perforated or stimulating zones perforated but not producing,to restore dead wells to production and capture additional reserves by sealing off zones of floodwater invasion and recompleteing in water-free zones,to prevent interzonal crossflow to water-free zones by plugging zones of water breakthrough,to improve waterflood conformance by opening selected new zones for water injection, andto restore to production wells off due to mechanical blockage in the tubing.

JPT

P. 1674＾
Effects of Fluid Saturation on Waves in Porous Rock and Relations to Hydraulic Permeability
Authors: Nur Amos M. , Walls Joel D. , Winkler Kenneth , DeVilbiss John
Published: December 2007

Detailed and very accurate measurements of compressional Vp and shear Vs wave velocities and their attenuation in dry, partly saturated and fully saturated clay-bearing sandstone were carried out at 20, 145, and 198°C, under variable confining and pore pressures.

The velocity results show that water saturated rock has high Vp and relatively low Vs not only at room temperature but also at 145 and l98°C. Varying the pore pressure reveals that the transition from the fully saturated to the dry state involves a gradual transition of Vs and a very irregular transition of Vp – with a minimum in Vp relative to either the dry or the fully saturated cases.

The attenuation of S and P waves – Qs−1 and Qp−1, respectively - shows similar patterns: in dry rock, both Qs−1 and Qp−1 are low. In fully saturated rock, Qp−1 is low and Qs−1 is high. In partly saturated rock, Qs−1 changes gradually with saturation, but Qp−1 shows a very strong maximum-suggesting strong energy dissipation. The same behavior is observed at 145°C, with the steam/hot-water transition. It was also found that attenuation of shear waves increases with permeability in some sandstones, consistent with squirting attenuation mechanism.

The results suggest diagnostic characteristics for determining the degree of saturation in situ from seismic logs, with particular applicability to evaluation of steam content in geothermal reservoirs and of gas content in oil reservoirs.