bluuebunny/crossref_metadata_2025 huggingface dataset:
Electrical Resistivity of Geothermal Brines
Authors: Ucok Hikmet , Ershaghi Iraj , Olhoeft Gary R.
Published: December 2007

Introduction

The electrical resistivity of dilute aqueous salt solutions has been studied for a number of years, but very few data exist on concentrations above 0.1 molar. Normal groundwaters commonly are near 0.1 molar, while most geothermal and oilfield fluids are at least several molar (Table 1). Thus, the interpretation of electrical measurements in geothermal areas at present is based mainly on extrapolation of lower temperature and lower concentration data. Such extrapolation may introduce serious errors into the interpretation of geothermal reservoir characteristics determined from electrical measurements. This paper presents new experimental data and an improved descriptive model of the electrical properties of brines as a function of temperature properties of brines as a function of temperature from 22 to 375 deg. C and concentration from roughly 3 to 26 wt% while under 31 MPa hydrostatic pressure. Data and models are given for brines composed of the chlorides of sodium, calcium, and potassium, and their mixtures. Comparison of the older log interpretation formulas to the new models illustrates an order of magnitude improvement in accuracy with an overall fit to within 2%.

Resistivity Dependence Upon Temperature

Some researchers have postulated that the electrical resistivity of fluid saturated rocks follows the temperature dependence of the saturating fluid in the absence of conducting minerals or significant surface conduction along altered pore walls. This assumption resulted from the success of a simple empirical formula relating the resistivity of a rock to the resistivity of the fluid filling the pores of the rock:

Pr=FPw,

where

Pr= resistivity of clay-free, nonshale material that is 100% saturated, Pw= resistivity of saturating solution, and F= formation resistivity factor.

A number of investigators have derived formulas that add the temperature of the saturating fluids. Experimental observations have shown that some rocks obey these formulas while others do not. 17–19 Part of the problem is the inadequate knowledge of Part of the problem is the inadequate knowledge of the resistivity dependence on temperature for the solution that fills the rock pores. We have found empirically that the best fit of the resistivity data to temperature is

pw=bo+b1T-1 +b2T+b3T2+b4T3,

where T is temperature and coefficients b are found empirically.
Chemical Treatments Associated With North Sea Projects
Authors: Mitchell R.W. , Grist D.M. , Boyle M.J.
Published: December 2007

This paper discusses carbonate and sulfate formation in the Forties field and some of the laboratory inhibitor-selection techniques used to evaluate scale inhibitors for field use in the Forties injection and production systems. Two chemical treatments for stimulation injection wells also are described.

Introduction

Pressure maintenance in the Forties field began in Dec. 1976. Initial water sampling and core injectivity studies indicated that seawater would be a satisfactory injection fluid.Before commencing injection, the chemical treatment requirements for the seawater injection system were determined. The principal requirement at that time was for an effective microbiological treatment. This was discussed in detail in an earlier publication. Since that time the need has arisen for injection of suitable scale inhibitors into both the injection and production systems to prevent calcium carbonate and barium sulfate scale formation. This paper discusses scale formation in the Forties field and some of the scale-inhibitor selection techniques used. In particular, a novel test method is described that is used to monitor inhibition and flow pattern influence on formation scaling.The water quality aspects of North Sea injection water have been discussed in detail previously. In that study numerous core injectivity measurements were carried out, and the major core plugging mechanism was attributed to the organic portion of seawater. Although no similar plugging has been detected downhole, BP Research has developed a suitable well treatment product to remove organic debris. Some of the results of this study are discussed in relation to potential field application.

Field Scale Problems

Scale problems occurring in the Forties field can be attributed to two major factors:commingling of Forties formation and injection waters andprecipitation of calcium carbonate scale from formation water due to variations in pressure and temperature in production systems.

A partial chemical analysis of Forties formation water and North Sea injection water is given in Table 1. It will be seen that the commingling of formation water and seawater can precipitate both barium and strontium sulfates, which probably are the worst types of scale found in oilfield situations. The solubility of barium sulfate has been calculated as a function of temperature and mixing composition. The results are shown in Fig. 1 and are presented as a stability index, which is the logarithm of the ratio of actual barium sulfate present to the barium solubility under the specified conditions. For example, a stability index of +0.3 indicates the actual barium sulfate present exceeds the solubility limit by a factor of 2 (10 (0.3)).The worst condition exists for relatively large amounts of formation water and small amounts of injection water.

JPT

P. 904＾
A Set of Equations for Computing Equilibrium Ratios of a Crude Oil/Natural Gas System at Pressures Below 1,000 psia
Authors: Standing M.B.
Published: December 2007

Use of equilibrium ratios (K values) to compute the quantity and composition of gas and liquid phases in equilibrium at given temperatures and pressures is documented extensively in the petroleum literature. While K values usually come from laboratory experiments, the values available to petroleum engineers are presented most often in the form of charts. The Gas Processors Suppliers Assn. (GPSA) charts of K data are well known in the industry.It long has been recognized that equilibrium ratios are system-compositional, temperature, and pressure dependent. Composition dependency usually is indicated by the apparent convergence pressure value (for example. 5,000 psia, 10,000 psia). However, at pressures below about 1,000 psia, the effect of the system composition is small and often may be neglected.A computer program package for evaluating GPSA ratios is available from the association. However, use of the GPSA programs requires a large computer. The equations presented here are simple enough to be handled by small programmable calculators, such as the HP-67, TI-52, and TI-59 machines. It is my opinion that K values developed from these equations are more appropriate than GPSA K values for calculating flash vaporizations at conditions usually found in oilfield gas/oil separation processes.The basic K data involved here are those developed by Katz and Hachmuth on recombined samples of gas and oil from the Wilcox sand of the Oklahoma City Field. Crude gravity was 38.4 deg. API. Based on the reported viscosity of the crude oil, 43.5 Saybolt Seconds Universal (SSU) at 100 deg. F, the Universal Oil Products Characterization Factor (UOP K) of this crude is judged to be about 12.2. While 22 sets of experimental data were determined at three temperatures (up to 3,422 psia), the K values used here were smoothed values read from 11- X 17 1/2-in. charts prepared by Katz and Hachmuth. The K values corresponded to pressures of 14,200, 400, 600, 800, and 1,000 psia, at temperatures of 400, 120 deg., and 200 deg. F.The basic equation used to correlate the Katz and Hachmuth data was that proposed by Hoffman et al.:

log Kp = f[b(1/TB- 1/T)).................(1)

where:

K= equilibrium ratio, y/x, of the compoundp= pressure. psia (MPa)T= temperature. deg. R (K)b= slope of the straight line connecting thecritical point and the atmospheric boilingpoint on a log vapor pressure vs 1/T plot

-log (pc /14.7)(l/TB - 1/Tc)

TB = boiling point of the compound at 14.7 psia, deg. R (K)TC = critical temperature of the compound, deg. RPc = critical pressure of the compound, psia(MPa)

The function inside brackets is the component characterization factor, designated by the symbol F.Several authors have shown that plots of log Kp vs F. at a given pressure. often form essentially straight lines. Also, the effect of increasing pressure has been shown to raise the position of the line on the plot and to yield a line of lesser slope.

P. 1193＾
Strategies for Reducing Oilfield Electric Power Costs in a Deregulated Market
Authors: Stiles Robert F. , Slezak M. Steven
Published: December 2007

Electricity is one of the single largest costs associated with oil and gas production. This cost, however, tends to be overlooked relative to other production costs because of utilities regulation combined with its specialized and noncore technical requirements. In spite of this, several studies and strategies over the years have looked at ways of reducing this cost component with meaningful results. Many of these strategies consist of structuring loads and designing equipment to take advantage of the utilities’ regulated rate structure. As the electricity industry in the United States moves toward deregulation, these rate structures will no longer exist; in their place, contracts will be negotiated on a free-market basis between the user and supplier(s) of electricity.

In the upcoming deregulated electricity market, three key strategies are available to effectively manage oilfield power costs.

Real-time monitoring and control of the electrical load. In-field electricity generation. Negotiation of an integrated power-supply agreement. Because electricity is the ultimate just-in-time product, prices vary greatly depending upon when the power is consumed. The strategies listed previously allow users to proactively structure power-supply systems to address the fundamental volatility of the real price of electricity. The effect is to strip out the historic premium paid to the utility to handle the natural volatility of electricity prices by blending load shifting, internal generation, and market purchases.

This paper examines different scenarios in which the previous strategies are proposed and makes estimates for potential savings. These solutions use existing technology applied to the changing market environment and, therefore, focus on economic justification as opposed to technology verification. In one such case, the pumping intervals for a collection of wells is adjusted with real-time power prices combined with remote operations. This reduces the total cost of electricity consumed per barrel of production while only marginally reducing the actual number of barrels produced.
Buildup Solution in a System With Multiple Wells Producing at Constant Wellbore Pressures
Authors: Camacho-V. Rodolfo , Galindo-N. Agustín , Prats Michael
Published: December 2007

This paper presents a new analytical solution to obtain the shut-in wellbore pressure at a vertical well that had been producing at a constant wellbore hole pressure from a closed-boundary reservoir with multiple wells producing at constant, different wellbore pressures.

The analytical solution is a set of coupled simultaneous equations in the Laplace space (one for each well). These are obtained by using separation of variables, Green's functions, and the unit-step function with the methods of Rodriguez and Cinco-Ley1 and Camacho-V. et al.2 The equation for the shut-in well is nonlinear, preventing us from obtaining the formal solution of the set of equations either in real time or in Laplace space.

A number of approaches were used to make the solution tractable. These included expansion of Green's function for large times, a Taylor series expansion of the rates around the time of shut-in, and application of the concepts of Najurieta.3 None of the approaches gave satisfactory results.
Estimating Oil Reserves of Fields With Oil/Water Transition Zones
Authors: Fanchi J.R. , Christiansen R.L. , Heymans M.J.
Published: December 2007

The amount of recoverable oil in an oil/water transition zone depends on the distribution of oil saturation as a function of depth and on the relationship between initial and final oil saturation in the transition zone (Soitz and Sortz), as well as the volumetric extent of the zone. Conventionally, it is assumed that Sortz is constant and equal to the residual oil saturation in the oil column (Sor) above the transition zone. However, limited data in the literature show that residual oil saturation depends on initial oil saturation as described by the trapped-oil relationship. Thus, Sortz should be a function of Soitz.

The purpose of this paper is to present recent experimental corroboration of the trapped-oil relationship and to demonstrate the impact of the trapped-oil relationship on reserves determination in oil/water transition zones. The effect of the trapped-oil relationship on reserves determination is shown in two ways: first, with an analytical model that shows the maximum possible incremental benefit of including the trapped-oil relationship; and second, with an extended black-oil simulation that incorporates the effects of relative permeabilities on reserves determination.
Seismic Determination of Saturation in Fractured Reservoirs
Authors: Brown R. L. , Wiggins M. L. , Gupta A.
Published: December 2007

Detecting the saturation of a fractured reservoir using shear waves is possible when the fractures have a geometry that induces a component of movement perpendicular to the fractures. When such geometry is present, vertically traveling shear waves can be used to examine the saturation of the fractured reservoir. Tilted, corrugated, and saw-tooth fracture models are potential examples.
Effects of Price and Availability on the Future United States Energy Market
Authors: Eisemann Eugene F.
Published: December 2007

This paper is concerned with the competition between fuels for industrial use in the United States. Energy consumption in the U.S. is allocated between industrial and other uses. The industrial volume is divided into two classifications-where there is competition between fuels, andwhere there is no competition.

The pattern of fuel consumption by electric utilities is studied intensively because there is competition between fuels and because it is the fastest growing industrial market. The growth of each utility fuel in several geographic areas is investigated.

The analysis of these areas includes the study of the relationship between prices where fuels are in competition; i.e.,on the East Coast where price competition is between oil and coal, andin the South East states where the competition is between coal and gas.

Introduction

The purpose in developing this energy study was to examine the future demand for petroleum products in the total United States consumption of energy. To predict growth in liquid petroleum fuels, it is first necessary to analyze the competitive position of each fuel in each of the markets it serves. In this approach to the problem, total energy consumption has been segmented into several broad classifications-residential uses, transportation uses, industrial uses, etc.
A New Diagnostic Method for Prediction of Producibility and Reserves of Wells Producing From the Monterey Formation Using Well-Log Data
Authors: Wylie Ursula M. , Ershaghi Iraj , Christensen Karen
Published: December 2007

Formation evaluation with well-log data is primarily a prediction tool for the purpose of identifying porous and permeable zones containing movable hydrocarbons. When the lithology is complex or the productivity is controlled by fracture density and the welllog data are limited in scope, underestimation of productive intervals can occur. This paper is a unique study on relating more than 28 years of actual production history to the initial well-log responses. This retrospective approach is the basis for presenting a diagnostic approach to predict producibility and reserves for other wells in the field under study or in other neighboring fields with similar geology.

The focus of the study is well-log responses in the Monterey formation, offshore California. The geology of this formation is regarded as a prime example of a heterogeneous matrix system and a lithology-dependent fracture network. The lithology of the Monterey formation is heavily influenced by the diagenetic stage of biogenic silica (comprising the bulk of the geologic column), the detrital content, and the calcareous component. The particular field selected represents the typical lithological and diagenetic stages observed in surrounding fields. As such, the proposed approach has merits for application to other fields. Geographically, the Monterey type sediments extend from Baja California all the way along the Pacific Rim to Japan.1 Extension of the lithological patterns observed and the productivity correlations in surrounding fields can lead to eventual development of a more general correlation for widespread exploratory or development wells in this type of formation.
Simulation of a Gas-Dominated, Two-Phase Geothermal Reservoir
Authors: Zyvoloski G. A. , O'Sullivan M. J.
Published: December 2007

The basic equations governing the behavior of a two-phase mixture of carbon dioxide (CO2) and water are discussed. A Newton-Raphson scheme, based on the alternating direction implicit (ADI) method for multidimensional problems, is used to solve the nonlinear finite difference approximation of the governing nonlinear system of partial differential equations. Sample calculations showing the behavior of hypothetical reservoirs with varying CO2 contents are presented.
Waterflood Performance Under Bottomwater Conditions: Experimental Approach
Authors: Shirif Ezeddin , ElKaddifi Khaled , Hromek Jonathan J.
Published: December 2007

In many light or moderately viscous oil reservoirs in Saskatchewan and Alberta, Canada, a high water saturation zone of varying thickness and extent ("bottomwater zone") occurs in communication with the oil zone above. As a result, the primary production period is short, and water breakthrough occurs very early in the life of the reservoir. Later, during the secondary recovery stage, such a zone can have an adverse effect on the waterflood efficiency. This paper addresses the problem of waterflooding such reservoirs.

This study was directed toward reducing water mobility in the bottomwater zone for more efficient oil displacement. Polymer in various concentrations was used as a blocking agent in the bottomwater zone and as a mobility-control agent in the oil zone. Different strategies were investigated to reduce the water mobility in the bottomwater zone and improve the vertical sweep efficiency. The variables examined were relative water-to-oil layer thickness, oil viscosity, polymer concentration, injection rate and injection point, and the effect of vertical and horizontal injection and production well combinations.

The results showed that oil recovery could be increased by minimizing crossflow between layers by blocking the bottomwater zone. It also was found that for an unfavorable mobility ratio, as the injection rate increases, the ultimate oil recovery increases. The injection of a polymer solution had a favorable impact on waterflood performance. Moreover, the worse the conventional waterflood performance was, the more effective the polymer was as a mobility and blocking control agent. The use of horizontal wells showed slightly better oil recovery over vertical wells in a conventional waterflood of reservoirs under bottomwater conditions. In addition, certain well combinations (horizontal production and vertical injection) gave better oil recovery because of the increase in the swept area.
Field Operation of Drilling Marine Risers
Authors: Childers Mark A. , Martin E.B.
Published: December 2007

Structural analysis techniques have been used since the 1950's to predict stresses in marine riser systems. However, little effort has been focused on the input design criteria, their interpretation, and field application. Taking into consideration the rig's characteristics, mooring capability, and riser system, this paper presents design and operating criteria for the engineer and rig personnel.

Introduction

Since the first marine riser (or mud riser) was run and operated in the late 1950's off the coast of California,1,2 the industry has analyzed and studied the structural aspects of drilling riser systems rigorously. Literally millions of dollars have been spent on computer programs and their refinement in an effort to analyze accurately the beam column structure as it is used on a floating drilling vessel.3–6 In search of field verification of developed analytical techniques, additional large sums of mopney have been spent for strain gauge and accelerometer measurements along with digital and analog recording systems.7 As of the mid-1970's, the industry generally had come to the conclusion that, from an analytical standpoint, the analysis techniques and conclusions were sound. This is apparent from the publication of API Bull. 2J8 as compiled by the Marine Riser Task Group, in which close agreement was obtained between nine different independent contributors.

The literature is full of presentations on riser structural analysis. However, no major piece of work has been presented on the methodology of taking the beam column computer output and implementing it on a daily basis in actual field operation. Because of this lack of attention, some interesting and varied results on how to design and operate a drilling riser in the field have taken place. It is our purpose (1) to show the tremendous divergence in approaches currently being used to determine a recommended tension and (2) to present a specific method for analysis that is based on operational considerations as well as riser structural stability.

We also will discuss field operations such as riser space-out, riser tensioner wire rope slip programs, and the inspection of marine riser joints and connectors.
Field Applications of a New Nuclear Magnetic Resonance Fluid Characterization Method
Authors: Freedman R. , Heaton N. , Flaum M.
Published: December 2007

This paper discusses the application of a new magnetic resonance fluid (MRF) characterization method to field data acquired by a nuclear magnetic resonance (NMR) well-logging tool. The theoretical and experimental foundation underlying the method was discussed in a previous publication.1 The MRF method provides a detailed formation evaluation of the near-wellbore region investigated by modern NMR logging tools. This information includes total and bound-fluid porosities, hydrocarbon saturations, oil viscosities, and hydrocarbon-corrected permeabilities. This paper presents MRF oil saturation and viscosity estimates in oil-bearing wells.

In this paper, we first provide a short review of the main ideas and key equations that make up the MRF method. We discuss the generalization of the MRF method to logging data acquired by the Combinable Magnetic Resonance (CMR)** tool and apply the method to mixture data acquired by a CMR tool on crude-oil and water samples.

We also discuss the existing database of MRF results on partially saturated rocks and present new laboratory results that include blind tests on Yates field dolomite rocks measured at initial and residual oil saturation.

The sources of uncertainty inherent in NMR diffusion-based viscosity estimation in reservoir rocks are discussed, and we propose a strategy that accounts for the uncertainties and provides reasonable estimates of oil saturations and viscosities. The strategy is applied to the MRF analysis of the field data in this paper.

The MRF method is applied to CMR station log data acquired in three wells. Analysis of the MRF data and the results from each of these wells is discussed.
Sampling Procedures for Oil Reservoir Fluids
Authors: Reudelhuber Frank O.
Published: December 2007

Introduction

The problem of determining the productive capabilities and ultimate yield of oil reservoirs is approached through use of various engineering calculations utilizing basic data. These data are concerned with the formation itself, the fluids contained therein, and the fluid-flow relations between the formation and the contained fluids. The first and last of these are obtained from core samples and are, in the main, based on an accumulation of data which can be evaluated and applied in a statistical manner. The fluid properties, on the other hand, are usually obtained from one sample and are applied to the reservoir as a whole. While considerable effort has been expended in developing the procedures for laboratory analysis, little his been done toward perfecting procedures for obtaining the samples from which all data are obtained and upon which, subsequently, all calculations are based. It is readily apparent that no laboratory procedures, however intensive, can result in sound engineering data from unreliable, possibly non-representative, fluid samples: therefore, it is important that every practical effort be made to obtain representative samples through proper well conditioning and sampling. Many of the difficulties encountered in sampling reservoir fluids can be avoided, or minimized, if samples are collected as soon as possible in the productive life of a reservoir. Some difficulties are inherent, however, and the following discussion is directed toward a better understanding of the problems involved and of the procedures available for collecting reliable fluid samples.
Ewald Method for the Analytic Solution of Simple Reservoir Problems With Neumann Boundary Conditions
Authors: Natoli Vincent D. , Pergler Joseph , Mifflin Richard
Published: December 2007

Analytic solutions to reservoir flow equations are difficult to obtain in all but the simplest of problems. Under the assumption of steady-state conditions, incompressible flow, and a translationally invariant permeability tensor, the Darcy equation leads to Laplace's equation for the hydrostatic potential. Methods of potential theory in both two and three dimensions may then be brought to bear on the problem, which is usually classified by the type of boundary condition. Dirichlet and Neumann-type boundary conditions, where the value of the potential and the flow respectively are specified on the boundary, are elegantly solved by simple superposition of sources in the case where the boundary is at infinity, or by Green's function techniques in cases with finite boundaries. Reservoir simulators, limited by the finite extent of their models, impose conditions on the flow at the boundary, which through Darcy's equation is proportional to the gradient of the potential. Analytic solutions to these Neumann boundary conditions are in general approached using the method of images to explicitly construct the Green's function for a point source. However, as can be easily shown, problems with no-flow boundary conditions lead to an infinite array of images. The sum of the potentials of the infinite lattice results in the solution in the simulation box. In this paper, we make use of the direct analogy between the reservoir flow equations and electrostatics to illustrate a method commonly used in the field of solid-state physics to sum the potentials of crystal structures. The advantage of this method is that it is fast, easily implemented, and may be used for an arbitrary configuration of injecting and producing wells, as long as net flow is zero. In addition, it is useful for a very general class of simulation boxes, not limited to orthogonal axes.
Unique Offshore Recovery System Dramatically Reduces Environmental Impact by Recycling Stimulation Proppant
Authors: Slater Martin , Perez Daniel , Teesdale Chris , Hilbig Nicholas
Published: December 2007

During the past 4 years, the use of multiple-zone proppant fractures has significantly improved production and the ultimate productive life of horizontal wells in the Valhall chalk field. A typical well is designed with up to 10 proppant-fractured zones. The stimulation technique involves pumping as much as 300,000 lb of proppant into each zone, and during this process, up to 70,000 lb of excess proppant may remain in the wellbore, which is cleaned out with coiled tubing. Because the material contains a resin coating to facilitate adhesion in the reservoir, disposal is restricted.

This waste previously had to be collected offshore, placed in large bags, containerized, and shipped onshore for incineration—a practice that was costly, wasteful, and environmentally suspect. In 1997, engineering studies revealed that the properties of the waste material made it suitable for recycling and use in future operations with minimal impact on fracture performance. While reusing proppant has become an accepted practice with no noticeable effect on well productivity, logistically it had some limitations. The material still had to be collected offshore and transported onshore, where it was stored for several months before being reloaded into the stimulation vessel for reuse in the next fracture treatment. This represents storage problems and environmental exposure of these materials. Furthermore, with no unforeseen delays, this was a 24-hour, two-way trip.

This paper describes the development and successful application of a unique system that allows the excess proppant to be collected, treated, and recycled on location. The authors will discuss the evolution of the recycling technique and discuss the stepchange improvement that allows the material to be immediately reused offshore using specialized vacuum equipment.

Approximately 150,000 lb of proppant was successfully recovered and recycled from the first well. The technique is still evolving and is likely to become a standard operation on Valhall wells. The offshore collection and recycling technique has eliminated the logistical problems associated with the previous method and will in time reduce the total proppant costs, along with minimizing the associated health, safety, and environment (HSE) impact.
Real-Time Specific Energy Monitoring Enhances the Understanding of When To Pull Worn PDC Bits
Authors: Waughman Robert J. , Kenner John V. , Moore Ross A.
Published: December 2007

Knowing when to change dulled bits can significantly reduce costs, which can be particularly important in high-cost environments. However, current techniques are based more on speculation and hope rather than science.

The concept developed to dramatically improve this inefficient decision process involved measuring the mechanical energy input at the drill rig floor, calculating the drilling specific energy (SE), checking the current formation type with real-time downhole gamma ray (GR) readings, comparing the SE with the benchmark new-bit SE, and then using these values to assess the bit's "dull" state.

This method has been proven to work in synthetic-based mud systems in which balling does not mask the bit's dull condition. It was imperative that the operator proved that this process worked in water-based drilling fluids that had replaced earlier synthetic muds because of environmental concerns, cost, and improved performance in water-based mud (WBM). Recently, the operator established that this process worked in water-based mud systems treated with antiballing chemicals. The case studies in which this methodology was developed are presented and discussed.
Management of Environmental, Social, and Health Issues Involving Indigenous Communities at the Villano Project in the Ecuadorian Amazon Region
Authors: Vacas Francisco , Gonzalez Mario , Sanabria Vinicio , Madera Angelo
Published: December 2007

As one of the leading oil and gas companies in the world, Eni has always operated with full respect for the culture, society, and environment of each country in which it works. Through the work of its affiliate companies, the Eni Group pursues an active policy of involvement and cooperation that aims at contributing to the overall socioeconomic well-being of the communities with which it interacts.

In Ecuador, Eni's affiliate, Agip Oil Ecuador B.V. (AOE), is the operator of Block 10 in the Ecuadorian Amazon region and is faced with a number of critical environmental, social, and health issues involving indigenous communities. Most of these communities belong to the Quichua ethnic group with other groups, like the Huaorani and Shuar-Ashuar, also represented. AOE's health programs cover more than 6,000 people, involving some 3,000 colonists.

The program is now in full development since its original inception more than 2 years ago (1999). It aims at protecting the environment and improving the quality of life for the inhabitants of more than 24 indigenous communities by providing primary health care. AOE has a comprehensive environmental-protection program as well as social and health programs. Agip is involved in disease prevention and control, health education, basic sanitation and safe water distribution, vaccination, nutrition, maternal and child care, treatment of common disease and injuries, access to essential medicines, and emergency medical evacuation. In addition, a new program is now being implemented to preserve the local tradition of natural medicine.

AOE's program is supported by the local branch of the Ministry of Health and nongovernmental organizations (NGOs), such INNFA (Inst. Nacional del Niño y la Familia) and SNEN (The Natl. Malaria Eradication Inst.).

As a result, this program has successfully reduced the morbidity and mortality rate in the region. At the same time, it protects the delicate environment of the Amazon region surrounding Block 10 and its area of influence, always respecting the culture and traditions of the people.
Case Study: First Intelligent Completion System Installed in the Gulf of Mexico
Authors: Nielsen V. B. Jackson , Tips T. R.
Published: December 2007

To maintain profitability in the development of marginal fields, many new technologies and concepts have been exploited. One of the most promising technologies has been the "Intelligent Well Concept," which allows the operator to produce, monitor, and control the production of hydrocarbons through remotely operated completion systems. These systems are developed with techniques that allow the well architecture to be reconfigured at will and real-time data to be acquired without any well intervention. This paper concerns a case history in the Gulf of Mexico in which an operator was able to justify completion of marginal wells based on the cost savings generated from innovative technologies.
A Field Test of Microemulsion Flooding, Chateaurenard Field, France
Authors: Putz A. , Chevalier J.P. , Stock G. , Philippot J.
Published: December 2007

A pilot test of microemulsion flooding was conducted in a single five-spot pattern in the Chateaurenard field in France. The test had to accommodate a 40-mPa·s (40-cp) oil viscosity and a regional pressure gradient across the pattern. A very clear oil bank was observed, resulting in a substantial increase in oil production.

Introduction

Société Nationale Elf Aquitaine (Production) is conducting a microemulsion/polymer flooding pilot test in its Chateaurenard field in the southern part of the Paris basin. This project involves the participation of the Inst. Franç du Pétrole, and it has been partially funded by the Commission of the European Communities. The primary objectives of the pilot are to (1) demonstrate the efficiency of the process under field conditions, (2) develop the technology involved in such an operation, and (3) assess the economics of fieldwide extension.

The permeability of the unconsolidated sand reservoir is very high, and the connate water is fresh. Both of these factors are favorable for micellar flooding application. The oil is relatively viscous [40 mPa·s (40 cp)]. Even though the oil saturation is far from residual, the well effluents have a high water cut due to poor areal efficiency of oil displacement by water. A microemulsion flooding scheme, with its readily achievable mobility control, appeared to offer a feasible recovery mechanism. However, the injection of viscous fluids limits the injection rate and requires a higher concentration of chemicals. The Chateaurenard oil viscosity is above the limit of 20 to 30 mPa·s (20 to 30 cp) mentioned in some publications.1,2

The well arrangement is a 10´103-m2 (2.5-acre) inverted five-spot pattern with one observation well. The pilot area was determined through coring, logging, and interference testing. These data indicated an initial pressure gradient across the pattern.

Three separate injection phases compose the process: microemulsion, polyme, and chase water. Microemulsion was formulated using field crude and water. Injection was initiated in Feb. 1978 and followed by polymer concentration started in April 1979 and led to chase water in Nov. 1979. The polymer buffer has been overdimensioned somewhat to test specifically the efficiency of the microemulsion, without interference from poor mobility control following it.

A significant response was observed from the producing wells 2 months after the start of operations. In this paper we present pilot design, performance, and an interpretation of the results.

Field Description

The Chateaurenard field, outlined in Fig. 1, is part of the Neocomian (Lower Cretaceous) oil reservoirs found in the southern part of the Paris basin. They are located 100 km (62 miles) south-southeast of Paris; the oil-bearing zones extend over an area of 20 km2 (7.7 sq miles).
Offshore Pile Grout Monitoring Method
Authors: Brooks Fred A. , Ruez William J.
Published: December 2007

An electrical conductivity method of monitoring offshore pile grout isdescribed. By using this method, the initial appearance of the grout, itscontinued presence, the subsequent extent of set, and its quality can bemeasured remotely.

Introduction

The connection between the seabed and offshoresteel platforms is achieved by using tubular steel pileswhich are passed through the main leg and/or theskirt pile sleeves. The piles are either driven to final penetration or cemented in predrilled holes.Although piles passing through the main legs may beconnected to the structure by welding at the deck level, in many structures the anular space betweeneach pile and leg or skirt pile sleeve is filled to somepredetermined elevation with cement grout. Thepresence of annular grout can significantly enhanceplatform strength. This strength enhancement canbe included in platform design considerations if thedesigner can reasonably assume a given degree ofgrout coverage and quality.

Ref. 2 specifies minimum 24-hour compressivestrength for grout at 1500 psi (1034 kPa). API RP 2A(Section 6.12) also specifies that a "means should beprovided to determine that the spaces have been filledas required."The method described in this paperoffers a technique for satisfying the API standards, as well as providing other measurementsi.e.,the identity of the resident fluid in the annular space(fresh water, seawater, or air);the arrival of thecement top at predetermined elevations;the occurrence of cement "fallback" in the event ofpacker failure;the set of the cement; andthequality of the set cement.

In previous practice, visualobservations, diver-collected samples, andmonitoring of the volume of grout pumped havebeen used for these purposes.

For example, in the grouting of the piles of theCognac platform "the overflow of the grout at thetop of the pile sleeve was observed with the remote-control vehicle (RCV). The diver caught two samplesfrom the overflow in plastic bottles. The volume ofgrout pumped was about 40% in excess of thevolume of the annulus." These methods are limitedto practical diver operating depths and, with regardto the use of the RCV and the collection of overflowsamples, information is generated regarding only thegrout that overflows the annulus. Knowledge of thepermanent level of the grout and the quality of thegrout inside the annulus is lacking.

JPT

P. 2234＾
Rate of Return Calculations as a Measure of Investment Opportunities
Authors: Glanville James W.
Published: December 2007

Introduction

Investments or capital expenditures form the frame-work for a company's future development and are a major determinant of efficiency and competitive power. Consequently, the wisdom of corporate investment decisions has a profound effect upon a company's future earnings and growth. From the standpoint of the stockholder, an effective capital expenditure program is apparently the only bulwark against the seemingly endless inflationary spiral. From the standpoint of labor, capital expenditures represent the basic source of future income which must exist before wage advances can be made.

Any business is continuously faced with the problem of making investment decisions. For the large integrated oil company, opportunities for investment exist in enterprises ranging from marketing to petrochemical, to exploration for and development of producing oil properties. Even for the very small business the problem of reinvestment of earnings, expansion, or diversification is a continuing one.

Foresighted judgment is an essential requisite for wise decisions about capital expenditures. However, for such judgment to be sound, it must be based on an analysis of all the facts, many of which may be extremely technical and complex. Management needs an objective means of measuring the economic worth of individual investment proposals in order to have a realistic basis for choosing among them and selecting those that will mean the most to the company's prosperity and growth. Probably a business organization will not have adequate investment capital at its disposal to make all the investments which have the potentiality of producing a profit; and even given unlimited capital, there is a maximum number of investment opportunities which can be efficiently handled with a given size organization. Therefore, it is apparent that either limited capital or the size of the organization may restrict the number of investments which can be made in a given period. Choosing among these investment opportunities, therefore, is of paramount importance.
A High-Pressure Dry-Gas Miscible Displacement SchemeSimulation and Economics
Authors: Flores Jorge , Pawelek J.
Published: December 2007

To develop an enhanced recovery scheme for theCardium E pool, the feasibility of waterflooding andgas injection was examined. A compositional modelwas developed to account for mass transfer andchanges in composition of this undersaturated, highly volatile oil system. High-pressure dry-gasinjection was desirable to achieve a high degree ofmiscibility.

Introduction

The Caroline Cardium E pool, discovered in June1974, is approximately 65 km (40 miles) southwest ofRed Deer, Alta. (Fig. 1). The discovery well was theHudson's Bay Oil and Gas (HBOG) 10–16–34–06W5, which was followed by the drilling of five additionalwells in the Bearberry Cardium A pool(T34, R06W5).

The existence of a 23-km (14-mile) northwestextension of this Cardium trend was proved by thedrilling of the Pacific et al. Ricinus 10–22–36–08W5 inAug. 1975 and subsequently confirmed by the Pacificet al. Ricinus 11-28-35-07W5 in Jan. 1976. The arealextension involving T36, R08; T35, R07;and part ofT36, RO7 will be referred in this study as the areaoperated by Pacific Petroleums Ltd. The oil reservoirin these wells initially was referred to as the CardiumU pool.

In Aug. 1976, an application was filed with theAlberta Energy Resources Conservation Board(ERCB)** requesting a special 130-ha (320-acre)spacing unit comprising either the northern orsouthern half of the section. This request was basedmainly on the marginal economics for developingthis thin-pay, narrow-type reservoir. It was approvedby the ERCB in an order prescribing drilling spacingunits in the Caroline area that became effectiveNov. 1, 1976. On this basis, the well allowable wasapproximately 9 m3/d (58 STB/D).

By Dec. 1976, a total of 13 wells had been drilled inthe Pacific-operated area. At that time, based onpressure data and reservoir fluid analysis, Pacific pressure data and reservoir fluid analysis, Pacific filed an application requesting that the RicinusCardium E pool and the Bearberry Cardium A poolbe coalesced into the Caroline Cardium E pool.The ERCB's approval to this matter was given inFeb. 1977.1 As of June 1979, a total of 34 wells hadbeen drilled in the Pacific-operated area.

To develop an optimum enhanced recovery schemefor the Caroline Cardium E pool in the Pacific-operatedarea, the feasibility of a waterflooding andhigh-pressure dry-gas miscible displacement schemeshave been examined in this study. A number ofpapers have emphasized the field application of papers have emphasized the field application of high-pressure dry-gas or vaporizing gas miscibledisplacement. It has been shown that a miscibledisplacement of oil with dry gas can be accomplishedif the oil is rich enough in the intermediatecomponents (C through C). The reservoir fluid fromthe Cardium E pool, being a highly volatile oil, appears to be amenable to undergo miscibledisplacement under high-pressure dry-gas injectionand involving multiple-contact miscibility of the gaswith the reservoir oil.

JPT

P. 359
Nitrification and In-Situ Uranium Solution Mining
Authors: Johnson David , Humenick Michael J.
Published: December 2007

The objective of this research was to determine the potential for conversion of ammonia to nitrate as a result of uranium solution mining operations. The work included literature evaluation and laboratory experimentation in both batch and continuous sytems. Results have indicated that a potential for nitrification could exist for some portions of the solution mining operating cycle. However, inhibition of nitrification was observed due to high ammonia and peroxide concentrations. Nitrification of ammonia also was observed to occur due to chemical oxidation by peroxide.
Wellbore Stability Simulations for Underbalanced Drilling Operations in Highly Depleted Reservoirs
Authors: Parra J. G. , Celis E. , De Gennaro S.
Published: December 2007

The need to increase productivity and to reduce drilling formation damage favors the use of underbalanced drilling technology. The main idea is to drill with equivalent circulating densities (ECD) that are less than the formation pore pressure and to avoid contact between the drilling fluid and the formation. In highly depleted reservoirs, pore pressures can be very low. Therefore, extremely low-density fluids, such as foams, are used to achieve circulating densities lower than the pore pressure. In such cases, the induced modification of the in-situ stresses has to be supported mainly by the rock, with little contribution from the drilling fluid pressure. In that sense, the application of underbalanced drilling depends on the mechanical stability of the drilled formation, among other factors. In general, poorly consolidated, depleted formations are not suited for that technology. This paper presents the wellbore stability simulation performed to establish the feasibility of using underbalanced drilling in highly depleted reservoirs in western Venezuela. The in-situ stress field and the mechanical properties of the formation were obtained. Pore pressure as low as 800 psi at 5,500 ft (2.7 lb/gal equivalent fluid density) was measured. The finite difference method and an elastoplastic constitutive model was used to obtain the new stress, deformation, and pore pressure distribution. The undrained condition (immediately after the wellbore is drilled) as well as the drained condition were analyzed. The analysis showed that horizontal wells could be drilled in an underbalanced condition with low instability risk. Following the recommendations, four horizontal wells were drilled in underbalanced conditions. Values as low as 2.0 lb/gal ECD were used to drill the wells, and no wellbore instability problems were reported. Production tests showed an enormous increase in the well productivity index in comparison with conventional overbalanced drilling.