bluuebunny/crossref_metadata_2025 huggingface dataset:
The Extension of the Variable-Flux-Weighting Method to Multidimensional Problems Including Gravity and Capillarity
Authors: Lasseter Thomas J.
Published: December 2007

The variable-flux-weighting method has been shown to largely eliminate numerical diffusion at saturation discontinuities in two-phase flow in two-dimensional problems1. The method has been extended to multidimensional problems including gravity and capillarity. The method is derived from fractional flow theory and involves the computation of a variable weighting factor for the interface fractional flow between grid blocks. In order to eliminate numerical diffusion at shocks, the appropriate weighting has been found to be downstream weighting just ahead of the shock and upstream weighting otherwise.

In one-dimension, the saturation distribution for two-phase flow including gravity has been solved and compared with the analytical solution. The comparison is very good with no numerical diffusion apparent at the saturation discontinuity. Problems including capillarity nave also been solved. In this case there is no saturation discontinuity, but the method introduces downstream weighting at the upstream edge of the capillary fringe which effectively eliminates any significant numerical diffusion.

Two- and three-dimensional problems have also been solved which demonstrate the accuracy of the method. For three-dimensional problems, the current implementation of the VFW method is ten times slower than an upstream-weighting IM PES method.
A Finite Element Formulation of the Two-Phase Flow Equations for Oil Reservoirs
Authors: Gulbrandsen S. , Wille S.Ø.
Published: December 2007

In the present paper, the differential equations governing two phase, immiscible flow in porous media is solved by the finite element method.

The saturation of the wetting phase (water) and the non wetting phase (oil) have been used as independent variables. In this finite element formulation the saturation and pressure equations are solved simultaneously and the formulation is entirely implicit. The time derivatives are approximated by backward Euler differences. The Newton Raphson method is applied to solve the non linear equations.

The differential equations are solved in the original form without simplifications. The simulations are performed in a two dimensional model, but the algorithms will have equal advantages in three dimensional simulations. The results of the simulations are presented as saturation and pressure isocurves, and velocity vector field.
The Chemistry and Design of Scale Inhibitor Squeeze Treatments
Authors: Meyers K. O. , Skillman H. L.
Published: December 2007

The deposition of scale in the near-wellbore formation and production string can result in a significant decrease in well capacity. Correctly designed scale inhibitor squeezes can successfully prevent scale deposition and the corresponding productivity declines. However, inadequate knowledge of the chemistry of the scale inhibitor and its interactions with the formation can yield ineffective squeezes. Inappropriately designed squeezes may actually damage the formation.

This paper addresses the chemistry of phosphonate scale inhibitors and the application of that chemistry in inhibitor selection and squeeze design. Screening/design criteria discussed include scale inhibition, thermal stability, corrosivity, scale dissolving capability, solubility in the reservoir brine, compatibility with multivalent cations, and adsorption/desorption on the reservoir rock. These criteria are illustrated with the results of an inhibitor screening study for the Prudhoe Bay field. Laboratory and field results illustrate how inhibitor chemistry can be used to optimize squeeze design.
Alumina Gel Drilling Fluid for High-Temperature Use
Authors: Block J.
Published: December 2007

A new clay-free drilling fluid has been developed for use at temperatures up to at least 177°C (350°F). The fluid consists of an alumina gel (pseudoboehmite) viscosifier stabilized with various bulky anions. These bulky anions include inorganics, such as sulfate, and organics, such as tartrate and citrate. Filtration control is provided by a compatible cross-linked poly(vinyl alcohol). The fluid is highly shear-thinning (the n value in the power law model is less than 0.3), has shale stabilizing properties (based on laboratory tests with sodium bentonite and various shales), is divalent ion tolerant, and can also tolerate moderate NaCl levels.

The system has been successfully field tested in a deep well (4,823 m (15,824 ft) total depth) in western Oklahoma. Good properties were maintained through both the unweighted and weighted portions of the well. Penetration rates and rig utilization rates were compared with an offset well drilled with a dispersed bentonite mud, and the trends were favorable. If further field tests confirm laboratory data, this new mud system should be able to delay (or eliminate in some cases) the conversion to oil based muds.
Vinylsulfonate/Vinylamide Copolymers in Drilling Fluids for Deep, High-Temperature Wells
Authors: Hille M.
Published: December 2007

In the past it was necessary to formulate predominantly oil based drilling fluids for temperatures in excess of approx. 140°C/284°F. More recently, when high temperatures have been encountered, styrene sulfonate, maleic acid anhydride, polyacrylate and modified polyacrylate baaed dispersants have been used in drilling muds intended for very high temperature applications. Such products work satisfactorily in freshwater drilling fluids, but their performance falls with increasing electrolyte concentration. Water loss in freshwater systems is only moderately controlled, and they show practically no effect at all in saline drilling fluids. At temperatures over 200°C the thermally stable acrylate/acrylamide copolymers have only a limited application in drilling fluid systems because of their high sensitivity to even low quantities of calcium ion. The new vinylsulfonate/vinylamide copolymers close this gap in additives suitable for water-based drilling fluids in high temperature applications. To temperatures well over 200°C they stabilize the rheological and water loss characteristics of the drilling fluids, while remaining entirely unimpaired by the electrolytic composition of the mud.

This paper discusses the performance limitations of presentday-drilling fluid additives, and drawing from laboratory and practical examples, demonstrates the effectiveness of vinylsulfonate/vinylamide copolymers under the twin adverse conditions of elevated temperatures and high electrolyte concentration.
Thermal Stability of Surfactants for Steamflood Applications
Authors: Maini B. B. , Ma V.
Published: December 2007

The objectives of the study reported in this paper were to evaluate the thermal stability of commercially available surfactants at typical steam injection temperatures and to investigate the kinetics of the thermal degradation process. Surfactant stability tests were performed under conditions of high temperature (200 and 300°C) and pressures (6.9 and 10.35 MPa) for twelve different sulfonate surfactants.

Most of the tested surfactants displayed halflives of longer than 100 days at 200°C, while at 300°C halflives were typically less than 10 days. Alkyl benzene sulfonates were found to be superior to alpha olefin sulfonates for chemical stability at 300°C, while petroleum sulfonates were found to be the least stable. A comparison of alpha olefin sulfonates with different carbon chain lengths in the range of 14 to 28 carbon atoms showed that thermal stability did not vary with chain length. A comparison of the results obtained with solutions to which a small amount of KOH was added to increase the initial pH with those in which the pH was not adjusted, showed that the initial pH can have a significant effect on surfactant stability.

For complex mixtures such as petroleum sulfonates, the experimental data displayed an apparent second order behavior in sulfonate concentration. This was found, however, to be merely a reflection of a gradual shift from faster decaying components towards slower decaying components at the reaction front due to the more rapid depletion of the faster decaying components.
Extensional Viscosity Correlation With Mobility Control Buffer Flow Behavior in Berea Cores
Authors: Fernando R. H. , Glass J. E. , Burnett D. A.
Published: December 2007

The shear thickening phenomenon of mobility control buffers in flow through porous media is adressed through the use of high molecular weight synthetic water-soluble polymers (W-SP) blended with carbohydrate W-SPs. This approach is necessary to separate shear and extensional reponses of thickened fluids under deformation. In previous studies in which the elastic contributions are an important part of the fluid response (i.e., where the dimensions of the fluid are approximate with the boundary conditions or the relaxation time of the fluid is approximate with the duration time of deformation) the shear viscosity response has been observed to contribute to the magnitude of the extensional response. The complementary interaction can be separated by employing blends of a flexible synthetic W-SP with carbohydrate polymers. In Berea core evaluation of such blends at practical frontal velocities the resistant factors observed were not proportional to the fluid's extensional viscosity. The permeabilities (160 mD) were only appproximate with the dimensions of the macromolecules and additional studies at lower permeabilities are in progress.
Interrelationships Between In-Situ Gas Hydrates and Heavy Oil Occurrences on the North Slope of Alaska
Authors: Collett T. S.
Published: December 2007

In 1973 during the drilling of the West Sak #1 well on the North Slope of Alaska, oil was first recovered from a shallow Cretaceous sand interval which was later informally named the West Sak sands by ARCO Alaska. Stratigraphically above the West Sak sands there are two additional oil bearing sands, and are informally referred to by ARCO as the Ugnu and the 2150 horizons. Oils in these shallow sands appear to have migrated from the nearby, more deeply buried Prudhoe Bay Sadlerochit reservoir and appear to have lost substantial amounts of light hydrocarbons as the deeper oil passed through the bubble point at approximately 1,219 m (4,000 ft) during updip migration, reducing the API gravity. In addition the shallow oil appears to have suffered biodegradation further lowering the API gravity. The updip portion of these three reservoir sands are within the gas hydrate stability field. Gas hydrates are interpreted to exist in the West Sak #6 well in conjunction with heavy oil and the physical properties of this oil may have been influenced by the gas hydrate. Prior to this work, only experimental evidence suggested that hydrates and oil could exist in the same reservoir.
Material Balance Depletion Models for Two-Phase and Vapor-Dominated Geothermal Reservoirs
Authors: Economides M. J.
Published: December 2007

Material balance calculations often referred to as "zero-dimensional" reservoir evaluations have been used extensively in petroleum and geothermal engineering. This paper presents a Havlena and Odeh-type1 material balance depletion model for two-phase reservoirs incorporating adsorption phenomena. A straight line, formed between groups of thermodynamic and adsorption properties of water and the cumulative production history provides the initial-fluid-in-place and the size of the vapor-dominated "steam cap". Adsorption phenomena were found by Economides and Hiller as the controlling mechanism in the depletion of vapor-dominated geothermal reservoirs. A material balance for vapor-dominated geothermal reservoirs, demonstrating the importance of adsorption phenomena is also presented. A straight line provides the initial-fluid-in-place.
Green's Functions for Solving Unsteady Flow Problems in Naturally Fractured Reservoirs With Arbitrary Fracture Connectivity: Part I—Theory
Authors: Wijesinghe A. M.
Published: December 2007

A general theory of Green's functions for solving boundary-initial value problems governed by two linear pressure diffusion equations coupled through a fluid transfer term which depends on the pressure histories, is presented. The governing equations, developed previously by Wijesinghe and Culham [1984], describe the flow of fluid in naturally fractured reservoirs with arbitrary fracture connectivity simultaneously taking into account both fracture and pore system permeabilities and unsteady interporosity fluid transfer. In this study, the relationship between the Green's functions (ie. generalized source solutions) and the adjoint Green's functions is determined, and the boundary conditions which must be imposed on the adjoint Green's functions to obtain explicit solutions for the fracture and pore pressures, are presented. The fundamental Green's functions, which characterize the basic properties of the two coupled differential equations, are derived and examples of their application to reservoir fluid flow problems are given. As in the case of the classical diffusion equation for fluid flow in single porosity formations, the Green's functions based on the present theory enable solutions to complex fluid flow problems in naturally fractured reservoirs to be systematically constructed from simpler source solutions.
The Effect of Annulus Water on the Wellbore Heat Loss From a Steam Injection Well with Insulated Tubing
Authors: Aeschliman D. P.
Published: December 2007

Recently completed field experiments using an instrumented string and test well have verified that the presence of annulus water in injection well annuli introduces a real and economically important heat loss mechanism--wellbore refluxing--for surface-generated steam. Measured boiling heat transfer rates at local hot spots are sufficient to maintain steady refluxing over a realistic range of injection conditions and overburden properties. It is shown that with the wellbore wet, the thermal properties of the cement and overburden, not those of the insulated tubulars, control the magnitude of the wellbore heat loss.

Steady refluxing without venting at the wellhead has been observed; hence, oil field operators should not automatically assume that a nonventing annulus is dry. Insulated couplings have been demonstrated to reduce coupling heat loss by up to 35% in a dry well, and in wet wellbores to prevent significant boiling at the couplings, typically the primary source of refluxing.

Heat loss estimates for refluxing or flooded wellbores indicate large incremental economic penalties, of the order of $100 million annually in the U.S. alone. The successful demonstration of simple, easily implemented, insulated coupling designs, and the confirmation that wellbore heat loss in refluxing annuli scales with annulus pressure in a predictable manner, suggests that much of this loss is preventable.
Relative Permeability Functions for High- and Low-Tension Systems at Elevated Temperatures
Authors: Kumar S. , Torabzadeh S. J. , Handy L. L.
Published: December 2007

Mathematical simulation of thermal oil recovery processes require relative permeability data at elevated temperatures. High-temperature, low-interfacial tension relative permeability functions are needed to predict the performance and efficiency of enhanced oil recovery methods in which chemicals are cohsidered for use with hot waterfloods or steamfloods. This paper presents empirical correlations based on experimental data that relate water-oil residual saturations and relative permeabilities to temperature, interfacial tension (IFT), and capillary number.

A new model has been found for relating residual saturation to capillary number. A modified capillary number is defined that better represents the low-tension, high-temperature systems. End point relative permeabilities have been related to residual oil/water saturations and the mobile water saturation range. The predicted values of residual saturations and relative permeabilities by these correlations are in good agreement with experimental data.

Two alternative approaches are presented for relating residual saturations to IFT reduction and temperature increase. The relationships are of necessity more involved than those discussed by earlier investigators who have studied only the individual effect of temperature or IFT reduction.
Economic Evaluation for Steam Injection Projects: A Simplified Model
Authors: Holcomb G. B. , Alcocer C. F.
Published: December 2007

Economic evaluations serve as the policeman of the petroleum industry. They determine whether or not a project will be undertaken. However, due to the complexity and nature of each petroleum project, an evaluation used in conjunction with one type of project may not be necessarily suitable for another.

This paper will introduce a computer program of a simplified model that deals with the economic evaluation of steam injection projects only. Steam injection ecompasses a large variety of methods, but all methods do have several economic factors in common. They include present and future cost of oil, taxes and operating costs. Other factors include past and present production, lease cost, discounted cash flows, as well as inflation.

The program also contains several features not usually found in the petroleum industry: It is user friendly, no user manual is required.Alterations may be easily made in the program, therefore, tailoring it to the project.It can be used with different steam injection performance models with minimum modifications.

As the need for oil increases, the implementation of steam injection projects will in turn grow proportionately. This trend will call for fast, efficient methods for analyzing such projects. This program fulfills that need. This paper provides a means for economic evaluation in thermal recovery projects.
Comparison of Alternatives for Deepwater Development in the Gulf of Mexico
Authors: Johnston D.
Published: December 2007

Significant attention is being given to exploration on the Continental Slope of the Gulf of Mexico. There are over 2.7 million acres under lease in water depths over 1,000 ft. Conventional fixed-platform developments become very expensive as water depths exceed 1,000 ft., and in some situations the recoverable reserves will not economically justify a fixed platform. Due to technical and economic constraints imposed by this environment, development systems and techniques other than the fixed platform are being seriously considered.

Present unconventional offshore installations, which were developed for marginal fields in the North Sea and other areas of the world, provide field-proven alternatives in the selection of a development system for deep water. A comparison is made here of the technical and economic aspects of such alternatives.
Exploration Decision Strategy
Authors: Smith M. D.
Published: December 2007

Investing in exploration for oil and gas reserves is very attractive when it can be demonstrated that the risk adjusted returns exceed the investment by a 2-4:1 margin.

To realize this type of margin the explorationist must focus on opportunities that demonstrate – by analysis of historical data – that these types of financial rewards are reasonable. The process for identifying exploration opportunities that fit this criteria is generally referred to as "trend" or "basis" analysis. The objective of the analysis is to identify the geologic trends offering the highest probability of achieving a company's desired risk adjusted return on invested capital.

The author will present a process for conducting a trend analysis that is quick, efficient, and complements the explorationist's judgment about screening areas for investment. The process and support computer software consist of the following.

Build a historical database of well drilling and production information. Commercial sources for this database include the Texas Railroad Commission, Petroleum Information and DWIGHT'S Energy Data. Compute trend drilling statistics to estimate success ratios. Compute reserves added by recent exploration discoveries and set up a distribution of reserves by trend. Compute a distribution of development economics for reserve discoveries in a trend. Simulate drilling multiple exploration wells in each trend and calculate the risk adjusted return per trend. Rank trends by a financial indicator such as discounted or undiscounted cash flow to investment ratio. Simulate an exploration program where financial resources are allocated over several attractive trends and compute an allocation of funds to develop prospects and drill wells in each trend.

After the analysis process is complete, an allocation of funds is made to trends based on the combined effects of the probability of success and the probability of finding reserves of a given value. An exploration strategy is then developed which allocates personnel to prospect generation in the trends of interest or to analysis of investment opportunities with other companies.

The author intends to use a South Texas trend to illustrate the analysis process, to demonstrate the computer models and statistical techniques, and to show typical results.
The Demand for Exploratory Drilling: A Theoretical and Empirical Investigation
Authors: Rankin M. D.
Published: December 2007

The contract drilliing industry, on dry land and offshore, is by far, the most capital-intensive of the industries which comprise the upstream petroleum service sector. A drilling rig, once assembled, has a usable life of 10 to 20 years and has little value in any use other than that of petroleum exploration and development. The typical land rig employs an average of 18 individuals and an offshore unit will provide year-round employment for 60–100 personnel. These numbers do not account for the multitude of operator and service company positions which are linked to each working rig.

In 1783 there were an average of 1,700 fewer rigs (land and offshore) were active in the U.S. compared to the peak drilling year of 1981. This decrease in activity represents at least 34,000 workers who were forced to look for other employment. Taking into account "ripple effects") a more realistic estimate of displaced workers might be on the order of 70)000. At an average of $10 million per rig in plant and equipment) the slump accounted for $17 billion in idle capital; easily $3.7 million per day in unsatisfied depreciation charges.

Average rotary rig activity for 1983 represented 36 percent of the level reported for 1981 yet the A.P.I's tabulation of exploratory wells drilled in 1983 was 92% of the 1981 number and the similar statistic for development wells was virtually 99%. Over the same period) crude prices dropped some 18% in nominal terms – a 20% reduction in real value.
Evaluation of Production Loans for Gas Properties in Today's Economic Climate
Authors: Watson S. L.
Published: December 2007

The evaluation of gas producing properties is made more difficult by increased market competition from fuel oil, random production curtailments and the abrogation of contracts. The bank engineer must construct a cash flow projection which incorporates a combination of technical and market factors from incomplete information in a rapidly changing market. By using a technical determination of the reserves as a target, he can forecast production rates that are consistent with anticipated market conditions.
Predictions of Size and Orientations of Lenticular Reservoirs in the Mesaverde Group, Northwestern Colorado
Authors: Lorenz J. C.
Published: December 2007

Reservoirs deposited in a delta plain environment as part of the Mesaverde Formation have been penetrated by the three wells of the U.S. Department of Energy's Multiwell Experiment (MWX) in the east-central Piceance Creek basin, northwestern Colorado. These reservoirs are gas-bearing, low-permeability, sandy channel and splay deposits. Tight well spacing and an abundance of quality data from the MWX project make it possible to estimate reservoir width and orientation. Estimates of lens width were made independently by two techniques: 1) a well-to-well correlation/ probability method, and 2) by analogy to height-to-width ratios of similar lenses exposed in surface outcrops. Estimates of lens trends were made using a combination of crossbedding in oriented core, crossbedding indicated by experimental high resolution dipmeter tool, and the spatial arrangements of lens thicknesses and channel subenvironments as recognized in core and logs. Splay deposits, recognized as a different suite of lithologies and sedimentary structures in core, have less easily defined boundaries, but limits can be placed on their general position.
Mini-Frac Pressure Decline Analysis for Fractures Evolving From Long Perforated Intervals and Unaffected by Confining Strata
Authors: Martins J. P. , Harper T. R.
Published: December 2007

When hydraulic fracturing operations are conducted in thick reservoir sections, it is common for the perforated interval to be long but yet still significantly shorter than the distance between reliable barriers to fracture propagation. Under these circumstances the fracture shape will change continuously as it evolves from the perforated interval, thus complicating the interpretation of pressure decline data measured during prestimulation mini-frac tests.

This paper presents a pressure decline analysis which assumes the fracture to have evolved as a family of confocal ellipses, which thereby ensures a smooth transition between the simpler fixed geometries which correspond to the injection of either very small or very large volumes of fluid (KGD and penny, respectively). The analysis enables the fracture shape and dimensions to be estimated, together with the fracture fluid-loss coefficient. An example is given of the application of this method, and a comparison is made with values determined assuming simpler, fixed shape models. The influence of injected fluid volume is considered. A rapid method for determining the Nolte "match pressure", P*, is also described.
A Review of the Long-Term Performance of Hydraulic Fracture Treatments in the Muddy "J" Sand, Wattenberg Field
Authors: Zahner R. L. , Crafton J. W.
Published: December 2007

A data base of production, fracture treatment, and volumetric data of wells in T2N/R65W, Wattenberg gas field, is used to evaluate the long-term (eight year) performance of hydraulic fracture treatments. Fracture dimensions are calculated using the procedure proposed by H. 0. McLeod, with modifications. proposed by H. 0. McLeod, with modifications.

Fracture design optimization must consider several variables in light of the general uncertainty of formation properties and created fracture shape and dimensions. Operators with limited leasehold positions generally cannot justify the expense of positions generally cannot justify the expense of rigorous optimization methods incorporating finite difference simulators. However, the results presented here strongly suggest that some type of optimization procedure is required to reduce the economic risk procedure is required to reduce the economic risk in drilling and completing wells in the Muddy "J" formation.
Horizontal Radial Drilling System
Authors: Dickinson W. , Dickinson R. W.
Published: December 2007

A high pressure, water jet drilling system has been developed using a new force system to concurrently drill a bore hole and place a metal tube in the bore hole.

The first commercial application has been horizontal radials for shallow heavy oil reservoirs. Many radials may be placed at the same elevation. Logging, and completion techniques have been developed.
New Technology for the Development of Deepwater Offshore Gas Fields Exemplified by the Troll Module Concept
Authors: Varvin K , Sollie L P
Published: December 2007

The Troll Module concept is one of several concepts under consideration for development of the Troll East field in the Norwegian sector of the North Sea. The concept is based on a direct transfer of unprocessed gas from subsea wells to shore or shallow water. A Troll Module base case for full field development of Troll East (PL 085) is described. The concept is considered feasible. However, some elements will have to be improved or better qualified to meet the standards required by a commercial project.
Development and Use of a 3D Simulator in Evaluating Reservoir Development Options: Fateh Mishrif, Offshore Dubai
Authors: Crick J , Singh S P
Published: December 2007

Fateh Mishrif, one of the largest reservoirs offshore Dubai, is a thick carbonate reefal development of which the centre has been completely eroded. During the past fifteen years production has been through natural depletion, peripheral water injection and gas lift. This paper describes the construction of a 3D reservoir model for the Fateh Mishrif reservoir and its application in evaluating further reservoir developments plans.

Significant reservoir factors which influence fluid flow are a field wide tar-mat, faulting and the central pinch out. The initial fluids in place description is affected by two oil-water contacts across the field. The model simulates these features accurately.

The prediction of future oil rates is based on an efficient gas lift optimization technique on a well by well basis which also provides a forecast of future gas lift requirements for the reservoir. The constraints on total available gas for gas lift and water injection rates, both field wide or regionally, can be modelled adequately. The model has been used for evaluating the expansion of the existing waterflood and future infill drilling potential. An important result of this study has been that the history matching phase has highlighted the need for further data gathering in specific parts of the reservoir.
The Application of Radioactive Tracers to Oil Reservoir Waterflood Studies
Authors: Wheeler V J , Parsons T V , Conchie S J , Durham B
Published: December 2007

Radioactive tracers are now commonly used to monitor the progress of water injection in oil reservoir secondary recovery schemes.

The injection water is labelled with a "water following" tracer (such as 3H2O, H14CO−3), and the produced water from the wells of interest is then sampled and analysed to determine the time to initial breakthrough and the subsequent tracer concentration profile. This may be compared with computer model predictions based on geological and operational data, and provide the reservoir engineer with a greater understanding of the reservoir structure and performance.

This paper discusses the factors involved in the selection of tracers, including their chemical form, and deals with the logistics of transporting and using radioactive materials offshore.

Counting techniques are described for the measurement of low levels of beta(β) and gamma(γ) -emitting isotopes, and computer models are presented for use in planning tracer studies and in interpreting the results.

Some field results are compared with these model predictions, indicating the application to reservoir engineering decisions.
In Situ Stress Measurements in Inclined Holes in the North Sea: Application to Water Flooding And Enhanced Oil Recovery
Authors: Teufel L W
Published: December 2007

Water flooding is typical for many North Sea reservoirs and enhanced oil recovery (EOR) projects are being considered for some reservoirs. A knowledge of the in situ stress state is important to reservoir engineers in designing water floods or EOR programs. Eighteen in situ stress measurements were made in two 3.6 km deep wells in an oil reservoir located in the northern Viking Graben region of the North Sea. The wellbores were inclined 60° and 65° from the vertical. The principal in situ stress directions and magnitudes were determined by the anelastic strain recovery method using oriented core immediately after it was retrieved from the wellbore. The maximum principal stress is the overburden, and the average ratios of the maximum and minimum horizontal stresses to the overburden are 0.94±.05 and 0.72±.07, respectively. The azimuth of the maximum horizontal stress and the direction of potential vertical hydraulic fractures created during a water flood or EOR program is N110°E±22°. This hydraulic fracture orientation is nearly perpendicular to the predominant trend of normal faults in the region. In order to achieve maximum efficiency of the areal sweep during a water flood or EOR, production wells should be located perpendicular to the azimuth of hydraulic fractures propagating from the injection wells.
The Argyll Field After a Decade of Production
Authors: Bifani R , Smith C A
Published: December 2007

The Argyll Field was discovered in 1971, brought on stream in 1975, and has the distinction of being the first oil producing field in the U.K. North Sea. Development wells have been completed with sub-sea wellheads and connected by flowlines to a floating production platform. After ten years of production the field has produced over fifty million barrels of oil.

Development drilling has proved commercial oil from five reservoir zones in rocks ranging in age from Devonian to late Jurassic. The geology of each zone is discussed in relation to environments of deposition, structure and reservoir parameters.

Field development and performance are reviewed and the timing and contribution of each reservoir to the production history are described. The benefits which have been achieved from continuing geological, petrophysical and engineering studies for identifying and establishing further development possibilities are emphasised. The complex nature of the reservoir and its effect on fluid movement and productivity are explained. The field has been produced by natural depletion which has been achieved by virtue of an efficient water drive.

This paper highlights the importance of geology and engineering in reservoir development planning.
Cost Effective Quality Management for all Phases of Offshore Operations
Authors: Burgess N T , Kitson J M , Kemp M J
Published: December 2007

The paper comments on the existing use of quality assurance in all phases of oil and gas field development. It identifies the objectives for the use and the problems currently being experienced during the implementation of Project QA Programmes.

Some important possibilities for making a more rational and therefore cost effective approach are given.
Offshore Pipelines in European Maritime Areas – The Years Ahead
Authors: Smith C. J.
Published: December 2007

Oil and gas development within the European area has already moved into deep water with the Montanazo wellhead in 760 metres. Deep water activities will be common by the end of the century. Offshore exploration and production techniques have been developed for water depths in excess of 300 metres. For effective pipelaying in these depths, where diver assistance is difficult, totally integrated installation systems will be required. The paper discusses such systems and defines the deep water capabilities required for the system elements.

In conclusion it is argued that no system element can operate independently without a design interface within the total deep water pipeline installation system.
Redesign of the Thistle Salm
Authors: Dupont B. , Alexander D. , Bellamy D. G.
Published: December 2007

In October 1983, EMH was awarded by BRITOIL the contract for the redesign of the THISTLE SALM. This paper describes the work covered by the contract and underlines the modifications to the design of the structure.

The contract was divided into two distinct phases.

The first phase, which started in November 1983, concerned the engineering of the project: a full hydrodynamic and fatigue analysis of the structure was carried out, reinstallation procedures defined, and the articulations and connection pieces redesigned.

The second phase, which started in March 1984, concerned the fabrication of the articulations and supervision by EMH.

Each step of the re-design is clearly defined and a detailed description of the articulations is illustrated by pictures of the most important components during fabrication.

The experience gained and the improvement to the system as a result of the modifications of the articulations is the subject of this paper.
TARA – Tartan Additional Riser Access System
Authors: Wheeler S A , Hunt R A M
Published: December 2007

The Highlander field is being developed using a remote subsea production centre, tied-back to processing facilities on the Tartan platform.

Weight limitations on the Tartan jacket prevented the tie-back of the subsea pipelines using conventional tie-on riser access systems. Therefore, a system was required which would not impose any vertical or environmental loads on the structure.

This paper describes the development of a system which met this requirement. Additionally, the system included the facility to change out individual risers, while others remained in use. The basic system, which utilises pile driven drilling conductors and flexible risers, is reviewed and the key system components discussed in detail.

The cost benefits, which are significant, are also reviewed, as is the installation method, which is seen as making a substantial contribution towards these reduced costs.

This system has been successfully installed and is now in operation.
Testing Program for Development of A High Pressure, Multi-Product, Fluid Swivel
Authors: Key J W , Mohr H O
Published: December 2007

This paper defines a rigorous seal test program conducted to develop a functional and proven high-pressure, multi-product swivel suitable for use as a Floating Production Storage and Offloading (FPSO) unit for the transfer of liquids and gases at high pressures and high temperatures through a rotating system.

The test program was accomplished with specially designed test equipment with computer monitoring of temperature, torque, fluid pressures, seal lip temperatures, number of cycles, and leakage. The three primary phases are: Seal material screening with a computer-automated Falex testing machine, plus physical testing of chemically exposed samples.One-third scale casting of several seal system configurations using a hydraulic driven, computer controlled test machine.Full scale testing of prototype swivel.

This paper documents the procedures for selection and testing of both the seal materials and the seal configuration. The test results clearly demonstrate the suitability of the selection, and testing process.
Sour Gas Processing for Gas Sales and LNG Production
Authors: Price B. C. , Zey A. F. , Ryan J. M.
Published: December 2007

The profitability of exploration and development of sour gas is sensitive to the processing required for marketing to gas pipelines or as liquified natural gas (LNG). Processing plants required vary widely with the composition of the produced gas. Processing will require removal of CO2 and H2S to meet marketing specifications and can range from simple sweetening and dehydration units to facilities including sulfur recovery and tail gas treating. Additionally, the production of LNG requires even more complete acid gas removal prior to the low temperature processing steps. Several new processes for acid gas removal have been developed which improve the profitability of sour gas production by more efficient acid gas removal. Additionally, the coupling of a cryogenic fractionation step with LNG processing results in an efficient integration of acid gas removal and low temperature processing.
Fordoche: An Enhanced Oil Recovery Project Utilizing High-Pressure Methane and Nitrogen Injection
Authors: Mayne C. J. , Pendleton R. W.
Published: December 2007

The Fordoche Field, Pointe Coupee Parish, Louisiana contains several high pressure retrograde condensate and volatile oil reservoirs. Since July, 1971, Sun Exploration and Production Company has maintained an extremely successful enhanced oil recovery program in two (2) of the volatile oil reservoirs, namely the Wilcox 8 and Wilcox 12 reservoirs. This paper reviews the reservoir performance and operational aspects of the EOR program.

The injection of dry natural gas with nitrogen at high pressures is predicted to result in a miscible displacement of reservoir fluids. Extensive reservoir modeling efforts predict that oil recovery will increase by an average of 19.5% over that of primary depletion due to the miscible displacement mechanism, the maintenance of reservoir pressure over 7000 psig, and due to highly successful operational practices.

Operational difficulties addressed are: the proper allocation of methane and nitrogen between producers/injectors, the ever increasing percentage of nitrogen in the gas stream which necessitates modifying plant and production facilities in order to keep equipment operating efficiently, the initiation of and monitoring of a radioactive tracer survey which commenced in January of 1985, and the evaluation of nitrogen rejection techniques for removal of nitrogen from the producing gas streams.
A Study of Nitrogen Injection for Increased Recovery from a Rich Retrograde Gas/Volatile Oil Reservoir
Authors: Huang W. W. , Bellamy R. B. , Ohnimus S. W.
Published: December 2007

Injection of nitrogen mixed with produced hydrocarbon gas is underway in a miscible displacement project in the Chunchula field, a Smackover dolomite rock containing undersaturated oil and gas phases in the same reservoir. An equation of state compositional simulator was used to describe the fluid and phase variations in the reservoir, match history, and to forecast field performance under the enhanced recovery operation. The numerical model was notably useful in optimizing oil recovery from regions of contrasting permeability. The model study showed that the efficient revaporization recovery mechanism can be interrupted and left incomplete as a result of shutting in producers, even though injection continues. A continuing history match of well pressure and gas-oil ratio data with the model will further improve our understanding of the heterogeneous reservoir rock.
Improved Use of Wireline Testers for Reservoir Evaluation
Authors: Gunter J. M. , Moore C. V.
Published: December 2007

Vertical pressure profiles obtained from wireline multiple pressure testers have become an important tool for improved determination of reservoir pressure and fluid distributions. Procedures and techniques for data acquisition to better ensure the quality of both strain and quartz gauge pressure data for vertical profiles are presented. Tool calibration checks, wellsite monitoring and consistency checks, techniques for normalizing pressure surveys within the same well or different wells, and sampling strategies are given. Examples are used to illustrate these procedures and techniques.

In addition, field examples of vertical pressure profile plots and interpretation of these plots are used to illustrate applications for: Defining fluid contacts and identifying oil reservoirs in fresh water environments.Defining multiple fluid contacts throughout an apparently continuous oil section.Identifying multiple pressure regimes in a supernormal pressure environment.Identifying zones of differential reservoir depletion as a result of low permeability or an impermeable barrier.Estimating fluid properties at reservoir conditions.
Experience: Offshore Drilling/Training in the People's Republic of China
Authors: Hammett D. S.
Published: December 2007

Drilling offshore the Peoples Republic of China by International Services Drilling Contractors commenced in 1983.

Two years experience have shown. that operations have been conducted with fewer problems than anticipated. Today seven (7) international contractors have imported mobile drilling units and drilled forty-four (44) offshore wells in the Peoples Republic China (PRC).

The mobile drilling equipment available today in the PRC can do the job effectively and safely with no additional development of technology. The factors which influence the efficiency of the operation are trained people, reliable offshore transportation and adequately utilized storm forecasting information.

The operation offshore PRC compares favorably with other areas of similar conditions.

The major items presented in this paper are: oA comparison of drilling in PRC to other similar areas.oOperation of semi-submersible in Typhoon area.oTraining of local personnel.oTechnology transfer to PRC.
Use of Data Center and Telecommunications in Drilling Operations and Engineering
Authors: Graff R. L. , Varnado S. G.
Published: December 2007

This paper describes a drilling data acquisition and telemetry system that is currently in use in the U.S. Gulf Coast. The system provides for the real time monitoring of up to 20 drilling rigs. Drilling data are acquired at the rig site and transmitted into a central office onshore over microwave or satellite telemetry links. The data acquisition units are advanced computer mud logging units that are capable of recording over 200 surface parameters relating to the drilling system. The data parameters are displayed in the central data facility in real time on graphic displays. The data parameters are subsequently analyzed in the office and used for providing safer rig operations through backup surveillance, improving rig management practices and for performing interpretive data processing using drilling engineering models. Drilling costs have been reduced by using this system. For example, the monitoring of connection times has led to a time savings of up to 1-1/2 days/month/rig. The paper will describe the processing and handling of the data in the central office facility. The cost savings thus far quantified will be explained.
Heavy Oil Production Practices in South Oficina Area
Authors: Ramirez N.G. , McHaney S.R.
Published: December 2007

Introduction

In recent years the market for low API gravity crude or heavy oil has increased tremendously. For this reason an extensive program for producing this type or crude was initiated some two years ago by Mene Grande Oil Company. This paper is primarily a progress report or one year's experience or producing 10to 11 API gravity crude. The primary source or heavy oil production is in the Merey Block or South Oficina Area in Eastern Venezuela.

Currently, approximately 40,000 BPD or formation crude oil is being produced by the bottom-hole blending technique from 200 wells in the Melones, Miga and Oleos Fields. This producing technique increases the gravity or the oil handled to 15 API, which minimizes many or the problems caused by viscous oils. By using this technique, an estimated initial capital saving or 15% on equipment will be realized. Production is carried from the producing fields through a 43-mile 24" pipeline to the Oficina Tank Farm where it enters a 98-mile 30" trunk line to Puerto La Cruz. The crude will deed into a 60,000 BPD refinery addition to the present Venezuelan Gulf Refining Company plant.

Heavy oil deposits are produced in other areas in Eastern Venezuela by various other methods, but these will not be discussed in detail.
Factors to Consider When Designing a CO2 Flood
Authors: Holm L. W. , O'Brien L. J.
Published: December 2007

Although many field tests since 1964 have demonstrated that CO2 is an efficient oil recovery agent, field-wide applications of CO2 injection have been rare becauselarge quantities of CO2 were not readily available at reasonable cost. A large supply of CO2 at a suitable price is nowavailable to West Texas oil fields, and plans are being made to provide similar supplies to oil fields in the Williston Basin, North Dakota, California and Colorado. As a result, many field applications are being planned in the United States and some are underway.

The authors discuss the response of CO2 to prevailing reservoir conditions which determine whether the flood will be miscible or immiscible. They conclude that reservoir pressure, temperature and oil composition are primary factors in determining how efficient the oil recovery will be. The authors discuss the laboratory tests used to define the optimum operating conditions and any deleterious effects from combining CO2 and oil (such as asphaltene or wax precipitation), the importance of developing an accurate reservoir description, and whether or not WAG (water alternated with gas) should be used to improve the recovery of oil by the process. Other techniques to control channeling of the injected CO2 and improve its sweep efficiency are also discussed.