bluuebunny/crossref_metadata_2025 huggingface dataset:
Nonstatic Reservoirs: The Natural State of the Geothermal Reservoir
Authors: Donaldson Ian G. , Grant Malcolm A. , Bixley Paul F.
Published: December 2007

Above-hydrostatic-reservoir-pressure gradients are found in many geothermal fields before exploitation. In higher-temperature fields, steam and water also coexist in the upper levels. These factors indicate natural upflow in these reservoirs-i.e. the dynamic state of the fluid. Analysis of flow and pressure data under these dynamic conditions can lead to relevant large-scale reservoir information.

Introduction

It has been suggested that the existence of a natural surface discharge from an oil reservoir must imply a nonstatic pressure distribution down through the fluid in that reservoir. To date, however, no such nonstatic pressure distribution has been identified in any oil reservoir. In contrast, most liquid-dominated geothermal reservoirs -- i.e., both hot water and two-phase -- have significant natural throughflow, and hence the nonstatic pressure distribution has been sought with interest. Until recently, the data supporting the enhanced pressure gradient have been sparse because wells commonly have been discharged, and the reservoir disturbed, before a suitable spectrum of data has been obtained. The mere presence of a significant length of open hole, as is commonly the case in geothermal exploitation, also distorts the pressure pattern. Study and reinterpretation of early (1950–56) Wairakei data have led to a much better picture of the natural pressure/depth profile for that field. In this paper we use this new information with other information about the reservoir in its natural state to determine an average (field) vertical permeability and the depth to which boiling may have occurred. Because the horizontal permeability of the flow strata is usually at least an order of magnitude higher than the mean vertical component (which includes the effects of any lower-permeability cross strata), it is horizontal permeability that controls the pressure transients of pump and injection tests. The vertical component is, however, important once water begins to drain down to the well feed level as the field pressure declines, and it has a strong influence over long-term behavior. Although we now can distinguish between liquid/water and steam/water (two-phase) conditions around a well, we are not yet able to pick up the phase-change boundary unless it is close. Even in long-term field tests, the horizontal/vertical permeability contrast may result in the pressure transients sensing the side boundaries before they show any effect of this horizontal one. Since extraction and injection from and into a two-phase section of a reservoir result in different effects from extraction and injection from and into a liquid-charged section, a pre knowledge of the depth of the two-phase zone could result in some savings in both drilling effort and costs.

The Geothermal Reservoir

It first was suggested at the beginning of the century that hot spring water might be meteoric water that entered the ground some distance away and circulated deeply enough to pick up the required heat.

JPT

P. 189^
Nonstatic Pressure History Analyses for Gas Reservoirs
Authors: Rodgers J. S. , Boykin R. S. , Coble L. E.
Published: December 2007

A method has been developed for using nonstatic pressure measurements directly in gas reservoir material balances composed of various energy mechanisms. Applying this method leads to simultaneous determinations of the reservoir p¯ history, gas in place, and other parameters relevant to water influx and effective compressibility.

Well-known methods1–4 of determining average static pressure, p¯, have at least two shortcomings: (1) an estimation of reservoir shape and (2) an often-neglected implicit relationship between p¯ and the viscosity-compressibility product. Errors resulting from these deficiencies are minimized by the proposed method through a simple coupling of the well-known pseudosteady-state flow and material-balance equations. The solution of this coupling is obtained through nonlinear regression, and it allows simultaneous evaluations of gas initially in place, static pressure history, and several other reservoir parameters. These parameters can include the initial reservoir pressure, a stabilized gas-deliverability constant, the effective compressibility, aquifer diffusivity, and aquifer volume plus water-influx constants. The results of applying the method to six published cases are presented to illustrate the utility of the method.
Miscible Drive Field Applications in the Seminole City Pool
Authors: Walker R.E. , Engel J.D. , Jenks L.H.
Published: December 2007

Introduction

This paper discusses a field test of a gas-driven liquid propane process being conducted by The Carter Oil Co. and supplements previously published information on the project. It presents a brief history of the still incomplete project and includes an evaluation of the method, based on present knowledge.

The process consists of injecting a predetermined volume of propane into a reservoir at a pressure above the vapor pressure of propane and driving the propane and oil to the production wells by means of an immiscible-phase gas drive. The test was carried out in the C–2 Block leases (Seminole, Okla.) in the Booch sand. The sand is about 3,600 ft deep, averages 30-md permeability and 18 per cent porosity, and ranges in thickness in the test area from 12 to 30 ft. Connate water is estimated at 35 per cent. The field was depleted by primary means for about 20 years and at the time the test started was producing 15 B/D at a gas-oil ratio of 7,500 scf/bbl.

History of Test

The reservoir was repressured with gas and 143,000 bbl of liquid propane were injected into two gas injection wells after which a gas drive of the propane was started. Since then total oil production has amounted to 142,000 bbl from five production wells. Approximately 12,000 bbl of this production is attributed to water injection which was used to create a barrier to hydrocarbon migration on the north end of the test area.

Breakthrough of injected propane into the production wells occurred almost immediately after the start of the test, contrary to laboratory experiments with linear, homogeneous models. About 73,000 bbl of propane have been produced for an over-all oil-propane ratio of 1.95. Approximately 600,000 Mcf of gas have been injected.

Because the field test is not only unconfined but also consists of incomplete well patterns, estimates have been made that only about 76,000 bbl of propane went into the test pattern and that approximately 40,000 bbl more oil would have been produced had the test been confined. This would yield a "recovery" of 2.2 bbl of oil per bbl of propane injected.
A New Device for Field Recovery of Barite: II. Scale-Up and Design
Authors: Burdyn R.F. , Hawk D.E. , Patchen F.D.
Published: December 2007

Earlier work on a mud separator for barite recovery is extended to the design and construction of a rugged field unit. Problems associated with scale-up for field use include the use of dilution water and its effect on capacity, power requirements and pressures developed. Equations for these quantities are derived and applied in maximizing the beneficial effects of dilution and minimizing the power required. Tests on the full-size rotor show that its performance can be predicted by theory. The completed unit is compact and lighter than current decanting types. Its capacity is from 10 to 22 gal/min with corresponding barite recovery efficiencies of 92 to 86 per cent.

Introduction

In an earlier publication a new type of centrifugal device was described for solid-liquid separations. In that paper an operating equation was derived, and its validity demonstrated in laboratory scale experimentation. Some of the features apparent in this new device seem particularly well suited to the conservation of barite in field drilling-mud systems, hence the development was extended to the design and construction of a field unit. In the present paper the design problems associated with scale-up are considered. A full-scale, rugged, self-contained field unit is described, and test results discussed which verify that the performance of the large field unit can be described by a simple operating equation.

PRINCIPLE OF OPERATION OF SEPARATOR

In principle, the new device is simply a perforated cylinder rotating within a body of fluid which is contained within a stationary case, as in Fig. 1. The frictional drag generated by the rotating cylinder causes part of the fluid to rotate. At the surface of the cylinder, assuming no slip occurs, the angular velocity of fluid and of the cylinder are identical. if there are suspended particles present of greater density than the fluid, the centrifugal force acting on these particles causes them to move radially away from the cylinder at some velocity, vp. Where the Stokes settling equation holds, this velocity may be expressed as:

....................(1)

If the case is provided with openings at both ends, a suspension can be pumped in at one end at a fixed rate. Part of the suspension can then be removed at a fixed rate at the other end of the case as underflow, and the remainder forced through the perforations and hollow shaft of the rotor to appear as effluent, also at a fixed rate. the radial component of the flow velocity of this stream as it reaches the rotor surface, is simply effluent flow rate divided by cylindrical surface area:

....................(2)

Because vp is a function of particle size, for some particular particle size, the velocities vp and vr will be equal in magnitude. This is defined as the critical particle size and represents the size above which all particles appear in the underflow and below which all particles appear in the effluent.

SPEJ

P. 100ˆ
Exploration, Development, and Reservoir Engineering Studies for the Tapis Field Offshore Peninsular Malaysia
Authors: Thu Goh Sing , Heacock D.W. , Loveless D.E.
Published: December 2007

This paper presents the rationale for oil development in the sandstone reservoirs of the Tapis field offshore Peninsular Malaysia. Pressure maintenance plans, well Peninsular Malaysia. Pressure maintenance plans, well spacing, and completion plans have been modified in response to data from exploratory and development drilling. Reservoir simulation has been a valuable tool in optimizing field development.

Introduction

The Tapis field is located in the South China Sea, 130 miles (209 km) off the east coast of peninsular Malaysia in 210 ft (64 m) of water (Fig. 1). Esso Production Malaysia Inc. (EPMI) has explored and developed the field as a contractor to Petroleum Natl. Berhad (PETRONAS), the Malaysian national oil company. Development plans for the field have been modified several times on the basis of data obtained from ongoing exploratory and development drilling. The producing reservoirs at Tapis are Miocene Age Group J (Tapis formation 1) sandstones that contain rim-type oil accumulations with associated gas caps. The three primary reservoirs, J-20, J-25, and J-30, are shoreface/barrier bar deposits separated by shale sequences. Both faulting and stratigraphic variations cause localized discontinuities across the field. Development wells from 4 platforms and 10 exploration wells have delineated most of the field. Reinjection of casinghead gas and waterflooding are being used to increase ultimate oil recovery. Two fieldwide reservoir-simulation studies have helped to optimize field development. These modeling efforts enabled selection of optimal waterflood pattern and determination of water-injection requirements, relative merits of commingled production vs. selective completions, benefits of gas injection, and recovery efficiency for the field. Detailed reservoir description work allowed assessment of reservoir continuity and assisted in selection of workovers needed to implement the waterflood.

Exploration

Exploration History

The Tapis field was discovered in 1969 with the drilling of Tapis Well 1 near the crest of the structure (Figs. 2 and 3). The well, Esso's first in the Malay basin, found gas in the sandstones of Groups J and K. In 1974, Tapis Well 2, drilled downdip to Tapis Well 1, discovered oil in the Group J sandstones. It encountered a gas/oil contact (GOC) in J-20, establishing a hydrocarbon column of 740 ft (226 m) and a proved oil column of 170 ft (52 m). Pressure and fluid data indicated that the lower Group J sandstones (J-20, J-25, and J-30) had common fluid contacts and were in a separate fluid/pressure system from the upper Group J sandstones (J-10 and J-15). In 1975, Tapis Wells 3 and 4 were drilled to delineate the Group J oil columns on the flank of the structure. Both wells encountered oil in the Group J sandstones and the lower Group J proved-oil column was extended to 1,516 ft (462 m).

JPT

P. 1051
Simulation of Two-Dimensional Waterflooding By Using Mixed Finite Elements
Authors: Chavent G. , Cohen G. , Jaffre J. , Dupuy M. , Ribera I.
Published: December 2007

A new method to simulate incompressible diphasic flow in two dimensions (2D) is presented. Its distinctive features include (1) a reformulation of the basic equation using the premise of a global pressure and (2) approximation of convective terms by an upwind scheme for discontinuous finite elements.

A mixed finite-element method approximates both the scalar functions (pressure and saturation) and the vector functions (total velocity field and capillary diffusion vector). The pressure (resp. the saturation) is approximated by a discontinuous function piecewise constant (resp. linear) on the elements of the mesh. A basis of divergence-free vectors is used in the pressure equation, which accelerates computation. Several test examples, which include gravity and capillary effects, are presented.
Numerical Simulation of CO2 Flood Performance
Authors: Chase Curtis A. , Todd Michael R.
Published: December 2007

A multicomponent, three-phase, three-dimensional (3D) reservoir simulator has been developed for predicting miscible flood performance with particular emphasis on CO2 flooding. Several features, not all normally found represented in either a black-oil or compositional simulator, are represented in the simulator described here. These features include (1) heavy-end dropout and concomitant reduction in phase mobility, (2) water blocking of oil from an invading solvent, (3) viscous instability (fingering) at the CO2 displacement front, (4) miscible/immiscible transition as a function of pressure and composition, and (5) loss of CO2 to the aqueous phase.

The solution scheme employs an implicit in pressure, explicit in saturation and composition time integration scheme (IMPES). This scheme allows for ready use of a second-order correct spatial discretization. We have found that for field applications, a numerical grid fine enough to represent waterflood performance accurately is usually sufficient for representing CO2-miscible-type processes as well. The program automatically employs a stabilized Runge-Kutta time discretization to alleviate the usual stability limitations imposed by the IMPES procedure. Up to 49 times the usual stable timestep size can be employed for seven times as much computing work. Work required to simulate a given time period when stability is limiting was improved overall by a factor of seven. To date, we have not encountered a pattern flood displacement simulation where the increased timestep size provided by the Runge-Kutta scheme has not been adequate to maintain stability for timesteps chosen so as to limit truncation error.

The CO2 flood simulator described has been in application for 4 years. The simulator has been used for design of CO2 EOR projects and interpretation of CO2 injectivity tests in several low-temperature west Texas San Andres dolomite reservoirs as well as high-temperature sandstone reservoirs. In addition to CO2 applications, the simulator has been used for the design of liquefied petroleum gas/dry gas flooding processes and for examining the effect of injection gas composition on oil recovery performance for immiscible gas drives.
General Purpose Compositional Model
Authors: Ács Gábor , Doleschall Sándor , Farkas Éva
Published: December 2007

A direct sequential method has been developed to simulate isothermal compositional systems. The solution technique is the same as that of the implicit pressure, explicit saturation (IMPES) method: one pressure is treated implicitly and (instead of the phase saturation) the component masses/moles are treated explicitly. A "volume balance" equation is used to obtain the pressure equation. A weighted sum of the conservation equations is used to eliminate the nonlinear saturation/concentration terms from the accumulation term of the pressure equation. The partial mass/mole volumes are used as "constants" to weight the mass/mole conservation equations.

The method handles uniformly a range of cases from the simplified compositional (i.e., black-oil) models to the most complicated multiphase compositional models of incompressible and compressible fluid systems. The numerical solution is based on the integrated finite-difference method that allows one- (ID), two- (2D), and three-dimensional (3D) grids of regular or irregular volume elements to be handled with the same ease. The mathematical model makes it possible to develop modular versatile computer realizations; thus the model is highly suitable as a basis for general-purpose models.
A Generalized Compositional Approach for Reservoir Simulation
Authors: Young Larry C. , Stephenson Robert E.
Published: December 2007

A procedure for solving compositional model equations is described. The procedure is based on the Newton-Raphson iteration method. The equations and unknowns in the algorithm are ordered in such a way that different fluid property correlations can be accommodated readily. Three different correlations have been implemented with the method. These include simplified correlations as well as a Redlich-Kwong equation of state (EOS). The example problems considered are (1) a conventional waterflood problem, (2) displacement of oil by CO2, and (3) the displacement of a gas condensate by nitrogen. These examples illustrate the utility of the different fluid-property correlations. The computing times reported are at least as low as for other methods that are specialized for a narrower class of problems.
Simplified Water Influx-Pressure Calculations Above the Bubble Point
Authors: Stewart F.M.
Published: December 2007

Introduction

A paper by Hurst and van Everdingen in 1949 led to the practical solution of many nonsteady-state flow problems. Subsequently, applications of this material have been discussed by several authors. The purpose of this note is to outline a simplified direct procedure for water-influx pressure predictions for pressures above the bubble point. The proposed procedure is unique in that after the "time-conversion factor" and the "influx constant" are obtained, predictions are made without trial and error. The elimination of trial and error is made possible by expressing certain PVT characteristics as explicit functions of pressure. The procedure is applicable to fields producing at pressures above the bubble point and under radial water drive from an infinite aquifer. In the usual applications it is required to predict (1) withdrawals given future pressure history or (2) reservoir pressure, given future withdrawals or production.

The theory, assumptions and conditions under which the nonsteady-state solutions hold are covered in the references and are not repeated. The simplified direct procedure outlined here has been developed from published solutions for the so-called "pressure case". A similar direct procedure for the same special conditions has been developed for the "rate case"; however, in this instance the procedure is lengthy and offers no advantage over the trial-and-error so1ution. Consequently, this paper covers only the procedure based on the pressure case.

Discussion

Under the pressure case prediction of withdrawals from a waterdrive field, given the future pressure history, involves the use of a nonsteady-state water-influx term together with the material balance equation. The solution of a particular problem requires the following steps:division of past pressure and production data into equal time intervals;computation of cumulative water influx vs pressure drop for each time interval of past history using the material balance equation;determination of the best values for the "time-conversion factor" and the "influx constant" by equating the nonsteady-state influx term with the influx computed in Step 2 (this requires a trial-and-error procedure);prediction of influx for a given pressure drop using the influx term and the computed factors from Step 3; andcalculation of fluids produced using the predicted influx in the material balance equation.

A forecast of the water-oil ratio or water production rate is required to complete the calculation.
Reservoir Simulation on Supercomputers
Authors: Levesque John M.
Published: December 2007

Several important excerpts from reservoir models have been tested on the Cray-1® and Cyber 205.1–3 The timings of these kernels are examined and explained by analyzing the architectural differences of the two machines. Interesting conclusions as to the strengths and weaknesses of the two machines are drawn.
Influence of Block Size on the Transition Curve for a Drawdown Test in a Naturally Fractured Reservoir
Authors: Braester Carol
Published: December 2007

Block size is considered one of the main parameters of a fractured rock reservoir. In one-phase flow, it controls the transition from the early stages of production to asymptotic behavior, and in two-phase wettingnonwetting displacement it controls the rate of production by imbibition. In nonwetting-wetting displacement it controls the pressure difference between the extremities of the block, which, provided that the threshold pressure is exceeded, permits displacement of the nonwetting fluid from the blocks into the fractures.

Warren and Root1 relate the size of the block to the transient pressure variation from the first to the second straight line of the drawdown/buildup test.

The numerical solutions presented in this paper for reservoirs with ordered fractures and blocks show that the drawdown pressures are not sensitive enough to the variation in sizes of the block. This means that a drawdown/buildup test cannot yield a solution unique for the size of the block.

In most practical cases of the one-phase flow, transition to homogeneous behavior is reached in a relatively short time and not noticed, except in a narrow region around the well. Therefore, in terms of reservoir performance, only the homogeneous behavior is of practical interest and the size of the block is not a relevant parameter of the one-phase flow.

It is believed that in two-phase flow the displacing fluid circumvents the blocks in groups rather than singly. If so, the individual size of the block is not a relevant parameter, even in two-phase flow.
On the Relationship Between Formation Resistivity Factor and Porosity
Authors: Pérez-Rosales Candelario
Published: December 2007

A theory on the relationship between formation resistivity factor and porosity is presented. This theory considers that, from the standpoint of the flow of electric current within a porous medium saturated with a conducting fluid, the pore space can be divided into flowing and stagnant regions. This assumption leads to a general expression, and formulas currently used in practice are special cases of this expression. The validity of the new expression is established by the use of data corresponding to sandstones and packings and suspensions of particles. For the case of natural rocks, the theory confirms Archie's equation and gives an interpretation of the physical significance of the so-called cementation exponent.
Laboratory Investigation of Reduction of Fracture Pressures of Rocks by Intensive Borehole Heating
Authors: Clark Kenneth K. , Somerton Wilbur H.
Published: December 2007

The feasibility of reducing pressures needed to fracture formations by heating the borehole intensively has been investigated on a laboratory scale. Reductions in fracture pressures of heated Bandera, Berea and Boise sandstone cores were observed at various confining pressures, simulating reservoir stress conditions to a depth of 5,000 ft. Both permeable and impermeable borehole boundary conditions were tested.

Three heating conditions were used in the tests. One group of samples was heated in a furnace to a temperature of 600C, cooled to room temperature, and then tested for fracture pressures. Two other groups of samples were heated with a borehole heater to maximum borehole wall temperatures of 625 and 792C, then cooled and tested.

In all cases, heated samples showed substantial reductions in fracture pressures compared to unheated samples. The higher temperature borehole heated samples showed the greatest reduction, amounting to 70 per cent in the extreme case. In actual application to wells, it was concluded that fracture pressures may be reduced by 20 to 50 percent by intensive borehole heating before fracturing.

INTRODUCTION

Hydraulic fracturing of oil and gas wells is an accepted and effective technique for increasing well productivity in many areas, but is notoriously unsuccessful in other areas. The technique becomes less interesting for production stimulation purposes when excessive fracture pressures are necessary. Formations which do fracture but require high pressures, probably form horizontal fractures. There is good evidence to indicate that some formations do not fracture at all, but yield plastically under high pressure. Thus, any technique which will make formations easier to fracture or will reduce fracture pressures is potentially interesting to petroleum producers.

Horizontal fractures generally occur in planes of weakness, such as bedding planes, and at pressures equaling or exceeding the effective overburden stress. In the unusual case where planes of weakness do not exist, a slightly higher pressure must be applied to overcome the tensile strength of the rock. In general, high fluid-loss fracturing fluids are conducive to the formation of horizontal fractures.1

Vertical fractures, when they do occur, are initiated at pressures generally lower than overburden pressure and are favored by low fluid-loss fracturing fluids or impermeable boreholes. The pressure necessary to create a vertical fracture in an impermeable, elastic medium can be predicted from the so-called "thick-walled cylinder" equation:Equation 1

where pf = fracture pressure

sr=radial stress

st=tensile strength of medium.

This equation indicates that to fracture it is necessary to overcome a tangential compressive stress, induced by and equal to two times the radial confining stress, plus the tensile strength of the medium.
Collocation Simulation of Multiphase Porous-Medium Flow
Authors: Allen Myron B. , Pinder George F.
Published: December 2007

Hermite orthogonal collocation yields oscillatory and sometimes nonconvergent numerical solutions to convection-dominated oil reservoir flow problems. A new method of choosing collocation points emphasizes upstream values in the convective terms, yielding oscillation-free solutions to the linear convection-dispersion transport equation and convergent solutions to the Buckley-Leverett problem.
Determination of Alkalinity Losses Resulting From Hydrogen Ion Exchange in Alkaline Flooding
Authors: Novosad Zdenka , Novosad Jerry
Published: December 2007

Maintaining an effective level of alkalinity during an alkaline flood is of prime importance in design of this EOR process.

Alkaline solution can be consumed in the reservoir through interaction with both reservoir rocks and fluids. The rock/alkali interaction can be characterized as either chemical or ion-exchange reaction, and the magnitude of alkalinity consumption and its type must be considered when alkaline floods are designed for specific reservoirs. This is because alkalinity propagation in porous media is directly affected by the type of alkalinity loss. It has been shown previously that kinetically controlled mineral dissolution reactions may cause the produced alkalinity to plateau at a lower concentration than the injected concentration, whereas ion-exchange processes may cause characteristic delay in the produced alkalinity, which in turn delays tertiary oil production.1,2 The type and the magnitude of alkalinity loss therefore must be known to design a flood with alkaline concentration maintained at its optimum for the longest possible time.

This paper concerns determining alkalinity loss resulting from hydrogen ion exchange. The model describing the release of initially rock-bound hydrogen ions into solution in the presence of alkali has been previously proposed and investigated for California Wilmington and Huntington sands.1,3 According to this approach the mechanism for reversible alkalinity uptake is described by the following equation.
The Importance of Reliable Data in Gas-Condensate Recovery Calculations
Authors: Hinds R.F.
Published: December 2007

Introduction

With the continued deep drilling of today, increasing numbers of high pressure and high temperature gas-condensate reservoirs are being discovered. Correspondingly, the ranges of properties of gas-condensate reservoir fluids are also being increased. The literature contains several excellent reviews of the property ranges in presently known condensate reservoirs. When one examines these property ranges, it becomes apparent that the need for reliable data is great if the engineer is to evaluate properly or appraise a gas-condensate reservoir.

It is the purpose of this paper to present phase-behavior data that will point out some of the important variables that influence recovery from gas-condensate reservoirs produced by pressure depletion. All these variables may be resolved into two major categories: the hydrocarbon composition of the reservoir fluid and the physical properties of the reservoir. But the variables which we will consider are those which are usually determined from well tests shortly after discovery and are, consequently, readily available to the engineer. They are as follows:the producing separator gas-stock-tank liquid ratio,stock-tank liquid gravity, andreservoir temperature.

Laboratory depletion studies have been performed on several reservoir fluids to illustrate the effect of changes in the considered variables upon ultimate recoveries. The deviation factors, Z, of a series of reservoir fluids were determined experimentally to illustrate their order of magnitude and their effect upon the calculation of in-place reserves existing at high pressures and temperatures, The procedures followed in conjunction with the performance of these studies and their associated calculations are illustrated in Fig. 1. For the purpose of this paper, the depletion recoveries are expressed only in terms of per cent of initial stock-tank liquid, with the abandonment pressure assumed to be 500 psig.
Gas Well Stimulation Increases Production and Profits
Authors: Clinkenbeard Paul , Bozeman J.F. , Davidson R.D.
Published: December 2007

Various acidizing and fracturing techniques have been developed to meet gas well stimulation problems. Case histories from four major gas producing areas show that considering such problems on an individual well basis, in light of previous experience in the area, allows planning each stimulation treatment for maximum effectiveness. Despite the common opinion that stimulating old gas wells is unprofitable, results show that stimulating such wells has often resulted in substantial and profitable production increases.

Basic Stimulation Methods

Gas producers have used many variations of the basic stimulation methods, acidizing and fracturing, to obtain maximum production from gas wells. These various techniques are necessary to meet individual well conditions found in different formations and fields. A knowledge of the various stimulation techniques available and of the advantages of each should enable an operator to plan gas well stimulation treatments that will bring maximum production from either old or new gas wells.

Acidizing Techniques

Acidizing treatments using inhibited hydrochloric acid to enlarge pores and flow channels have been used successfully for many years. Ordinarily, an acid treatment is conducted by spotting acid opposite the zone to be treated, and then pumping it into the formation.

High-injection-rate acid treatments are a variation of the normal acid treatment. In such treatments, large volumes of acid are injected into the formation at from 15 to 75 bbl/min. Acid is usually pumped down both tubing and casing. Advantages of this technique are that the rapid injection rate penetrates deeper into the formation and breaks down a larger vertical extent of the pay zone.

A special acid is often used to achieve deeper penetration. This acid contains an additive which retards the acid's reaction rate on portions of the formation already contacted. However, the acid reacts rapidly with new, untouched formation rock. This retarded acid is especially valuable in formations which are highly acid-soluble because it penetrates far into the formation before becoming spent. By contrast, normal hydrochloric acid reacts rapidly in such a formation, quickly becoming spent in the immediate vicinity of the wellbore.
Effects of Mobile Water on Multiple-Contact Miscible Gas Displacements
Authors: Tiffin D. L. , Yellig W. F.
Published: December 2007

Miscible gas flooding using an alternate gas/water injection process (AGWIP) is presently being applied for enhanced oil recovery (EOR) in several waterflooded reservoirs.1–4 A mobile-water saturation in the vicinity of the miscible displacement front can occur in this process. To design field applications of miscible gas floods properly, it is necessary to understand the effects of water saturations above the connate saturation on the oil-displacement efficiency. Previous research on AGWIP has involved water-wet long-core flow tests using an injected solvent that is first-contact miscible with the in-place oil.5–13 Miscible floods employing CO2, enriched gas, methane, and flue gases, however, are rarely first-contact miscible with reservoir oils; the oil miscibility is normally achieved by a multiple-contact mechanism.

This paper discusses the effects of mobile water on multiple-contact miscible displacements under water-and oil-wet conditions. Tests were conducted in 8-ft (244-cm) water- and oil-wet Berea cores in which CO2 and water were injected both separately and simultaneously to displace a reservoir oil. The data presented focus on effects of water in the oil-moving zone (OMZ) where the CO2 is generating miscibility with the oil and mobilizing residual oil to waterflooding. Special emphasis is placed on understanding the effect of mobile-water saturation on the oil-displacement efficiency and the component transfer between phases necessary to develop miscibility in the CO2/reservoir-oil system.

This study demonstrates that reservoir wettability is a key factor in the performance of AGWIP. Gas/water injection can, under certain conditions, have adverse effects on characteristics of the OMZ. These effects are in part caused by the water trapping portions of the oil and solvent. It was observed that mobile water did not change the mass transfer process by which miscibility develops in a multiple-contact miscible displacement.
A Numerical Method for Computing Recovery of Oil By Hot Water Injection in a Radial System
Authors: Fournier K.P.
Published: December 2007

This report describes work on the problem of predicting oil recovery from a reservoir into which water is injected at a temperature higher than the reservoir temperature, taking into account effects of viscosity-ratio reduction, heat loss and thermal expansion. It includes the derivation of the equations involved, the finite difference equations used to solve the partial differential equation which models the system, and the results obtained using the IBM 1620 and 7090–1401 computers. Figures and tables show present results of this study of recovery as a function of reservoir thickness and injection rate. For a possible reservoir hot water flood in which 1,000 BWPD at 250F are injected, an additional 5 per cent recovery of oil in place in a swept 1,000-ft-radius reservoir is predicted after injection of one pore volume of water.

INTRODUCTION

The problem of predicting oil recovery from the injection of hot water has been discussed by several researchers.1–6,19 In no case has the problem of predicting heat losses been rigorously incorporated into the recovery and displacement calculation problem. Willman et al. describe an approximate method of such treatment.1 The calculation of heat losses in a reservoir and the corresponding temperature distribution while injecting a hot fluid has been attempted by several authors.7,8 In this report a method is presented to numerically predict the oil displacement by hot water in a radial system, taking into account the heat losses to adjacent strata, changes in viscosity ratio with temperature and the thermal-expansion effect for both oil and water.

DERIVATION OF BASIC EQUATIONS

We start with the familiar Buckley-Leverett9 equation for a radial system:*Equation 1

This can be written in the formEquation 2

This is sometimes referred to as the Lagrangian form of the displacement equation.
A Model for Interfacial Activity of Acidic Crude Oil/Caustic Systems for Alkaline Flooding
Authors: Ramakrishnan T. S. , Wasan D. T.
Published: December 2007

The interaction of the alkali in floodwater and the acids in reservoir crude results in the in-situ formation of surfactants, which are responsible for the lowering of interfacial tension (IFT) in caustic flooding. The extent to which IFT is lowered depends on the specific properties of the crude oil and the injection water. Therefore, it is important to establish the relationship between IFT and the essential chemical properties of the acidic oil and the floodwater. This paper presents such a relationship.

In this discussion, the adsorption and the desorption of the active species at the interface are modeled as ionic processes using the Gouy-Chapman theory of the diffuse double layer. The interfacial potentials calculated using this model show a fair agreement with the experimentally measured trend of elcctrophoretic mobility. Also, the model rationalizes the experimentally observed effects of alkali concentration, salinity, and the oleic- to aqueous-phase ratio on IFT. We conclude that the acid number of the crude oil may not correlate directly with interfacial activity. Even in cases of low-acid-number crudes, significant interfacial activity could be obtained because of highly hydrophobic active species in the crude.
The Use of Simulation in Decision Making for the Kuparuk River Field Development
Authors: Clutterbuck Peter Richard , Dance Simon Edward
Published: December 2007

A multicomponent system of simulators has been used successfully for development decisions on the Kuparuk River field. This paper describes the field, the simulators chosen, and some decision examples. The system was found to be fast, flexible, and cost effective.

Introduction

The Kuparuk River field, west of Prudhoe Bay in Alaska, shares many problems with recently developed fields in the offshore and Arctic environments because capital costs are extremely high, lead times are long, and many of the development plans are made before useful production history is obtained. During the early development-planning phase, reservoir data acquisition accelerated and facility design revisions were frequent. BP Alaska Exploration Inc, (BPAE) and the Sohio Alaska Petroleum Co. (Sohio) are major shareholders in the Kuparuk River Unit and contributed to development plans. The BPAE/Sohio development team faced the need to compare options by using a rapidly changing data base, recommending decisions for a program that was fixed by target startup dates and seasonal windows. Output from the studies formed the basis for discussion with ARCO Alaska Inc. (ARCO), the Unit Operator, and for the adoption of a mutually agreed development plan. ARCO carried out similar studies concurrently, and all major field-development decisions were made jointly. This paper explains the system used by BPAE/Sohio to arrive at several major decisions through both simulation and experienced judgment to obtain an acceptable degree of confidence. The system used five simulators, either separately or combined, allowing a small team of technical staff to check the validity of results at intermediate stages. This was fast, flexible, and efficient. The views expressed, and the reservoir parameters quoted, reflect the authors' opinion and do not necessarily imply full agreement with other Kuparuk River unit working-interest owners.

Field Description

BP Alaska Inc. and Sinclair Oil Co. discovered the Kuparuk River field in 1969 on leases now held jointly by ARCO, BPAE, and Sohio. The field is 25 miles (40 km) west of Prudhoe Bay and covers an area of up to 200 sq miles (518 km2) of developable acreage. Fig. 1 shows the location of the field, the route of the Trans Alaska Pipeline System (TAPS) to the ice-free port of Valdez for tanker loading, and the summer sealift route. Fig. 2 shows a map of the field, and Fig. 3 records the field's discovery, appraisal, and development. Since Dec. 1981, the field has been unitized and produced at an average rate of 90,000 B/D (14 309 m3/d) oil. Fig. 4 outlines the probable development plan. A gathering system supplies oil from 40 to 50 drillsites to three central production facilities (CPF's). The first, CPF-1, produced oil initially from five drillsites, each with eight 320-acre (1.3 × 10 6 -m2) producing wells.

JPT

P. 1893^
Pressure Drawdown Analysis, Variable-Rate Case
Authors: Odeh A.S. , Jones L.G.
Published: December 2007

A theoretical development is presented which provides a straightforward method of handling the drawdown analysis for both oil and gas wells flowing at variable rates. In the past our inability to analyze variable-rate drawdowns has been a major obstacle in using them for formation evaluation. This method should permit wider use of these tests in the future.

Introduction

Pressure build-up analyses are widely used to obtain reservoir data such as the effective flow capacity of the formation. On the other hand, although pressure draw- downs have been run for a long time, they have not been used extensively to evaluate reservoirs because they are difficult to analyze. one of the difficulties in analyzing pressure drawdowns has been that the theory developed until now has required the test to be run at a constant rate. For both oil and gas wells this is a difficult requirement to satisfy, especially during the early period of a well's life when drawdown tests are usually run. in spite of this limitation, drawdown tests are often run with build-ups as a check. In this paper a theory, which handles the drawdown analysis for variable rates, is presented for both oil and gas wells. Thus, one of the biggest deterrents to running drawdowns is removed, and they should become a much more useful engineering tool in the future.

THEORETICAL CONSIDERATIONS

OIL RESERVOIRS

The general equation used for describing the unsteady- state radial flow of slightly compressible fluids in homogeneous porous media can be written in cylindrical coordinates as

(1)

where r is the radial distance in cm, t is the time in seconds, p is the pressure at r and t in atmospheres, phi is the fractional porosity, mu is the viscosity in cp, c is the compressibility in vol/vol/atm, and k, is the permeability in darcies.

There are a number of solutions of Eq. I for various boundary conditions. One of these is the so-called "point- source" solution, which approximates the case of an infinite oil reservoir with a well located at r = 0 and produced at a constant rate. The point-source solution of Eq. 1 is

(2)

and h is the net pay thickness in cm, q is the production rate in cc/sec, p is the original pressure at t = 0, p is the pressure at any t and r, and r, is the well radius. Eq. 2 describes the pressure drawdown of a well where the formation around it is neither damaged nor improved. If a condition of permeability damage or improvement exists, the equation must be corrected for these effects. van Everdingen introduced an additional term:

where S is the total flowing time for n constant-rate flow periods, t - t, t - t, ...t - t with rates q, q, ...q .

If we use Eq. 4 in its present form to construct a straight-line pressure drawdown plot, k, r, phi, mu, c and S must be known. This is so because for every t a variable factor

is left at the right side of the equation. This has been a major difficulty in analyzing a variable-rate pressure draw- down.

JPT

P. 960ˆ
Effect of Composition and Temperature on Phase Behavior and Depletion Performance of Rich Gas-Condensate Systems
Authors: Jacoby R.H. , Koeller R.C. , Berry V.J.
Published: December 2007

The experimental phase behavior of several field gas-condensate systems, one field volatile oil system, and a series of synthetic systems having gas-oil ratios from 2,000 to 20,000 scf/bbl stock tank oil was measured. The data were used to calculate the depletion performance of the field systems at their respective reservoir temperatures and of the synthetic systems at various temperatures. The results of the performance calculations were used to prepare correlations of total stock tank oil and separator gas in-place, and the amount of each recovered by primary depletion. Data needed to use the correlations are initial gas-oil ratio, initial tank oil gravity, reservoir temperature and reservoir pressure.

The correlations presented should be useful for estimating recovery from reservoirs producing volatile oils or rich gas condensates having gas-oil ratios from about 2,000 to 30,000 scf/bbl of stock tank oil.

Introduction

Prediction of depletion performance for gas-condensate reservoirs usually requires extensive laboratory work or lengthy phase-behavior calculations. For many small gas-condensate bearing zones the expense of such work is often not justified. Furthermore, where large holdings are involved, it is useful to have estimates of future oil and gas production in advance of the results of a laboratory analysis, even if such work is ultimately planned. For these reasons, it would be of value to have a method for rapidly estimating the depletion performance of gas-condensate reservoirs from the type of field data usually available. Few data on the reservoir depletion performance are available for the purpose of developing correlations. The increasing number of gas-condensate discoveries and the advent of high-speed computers have stimulated the development of methods for predicting performance. Such calculated performance data have been shown to be reliable and are becoming accepted as a basis for reserve estimates and for engineering studies. It therefore seems satisfactory to use results of performance predictions themselves for the purpose of developing the desired correlations.
Structural Repair Experiences in the Viking Gas Field
Authors: Jones Glyn R.
Published: December 2007

This paper discusses the problems in dealing with cracks on subsea nodes on in-service North Sea structures. Determining the cause of cracking before planning remedial action is an important aspect of guaranteeing a successful repair. Gathering information on the nature of subsea cracks to establish causes of cracking and assess crack significance is a task severely handicapped by the inadequacy of present inspection techniques. The causes of cracking can be many and various, ranging from poor steel properties to fatigue. Assessment of crack significance to the safety of a structure can make use of fracture mechanics techniques, but their inaccuracy in a complex node situation with unknown factors, such as crack profile and steel properties, has to be borne in mind. Many repair methods are available, ranging from hyperbaric welding to bracing, but the method used must be matched to the cause of cracking. Accurate measurements of the as-built geometry of structures, early repair site preparation, and attention to minor detail greatly reduce repair costs and enhance the chances of success.