bluuebunny/crossref_metadata_2025 huggingface dataset:
Relative Permeability Measurements Using Reservoir Fluids
Authors: Mungan Necmettin
Published: December 2007

Water-oil relative permeabilities measured using reservoir fluids and fresh, preserved cores are shown to differ considerably from those obtained routinely using relined fluids and extracted cores. Upon saturating the extracted cores with the reservoir fluids and allowing them to come to equilibrium, in this case for 6 days, the original relative permeability curves were reestablished.

Introduction

Ordinarily, relative permeabilities are measured using refined fluids and restored-state cores. On occasion, fresh core samples that had been flushed with a refined oil, without any other cleaning or extraction, have been used. To date, no relative permeability measurements have been reported permeability measurements have been reported using reservoir fluids and fresh preserved cores, although a number of published studies have dealt with the influence of core handling and other laboratory experimental factors on results of displacement tests. This is not surprising. Special procedures have to be followed for obtaining, procedures have to be followed for obtaining, preserving, and handling native-state cores; and preserving, and handling native-state cores; and companies are generally reluctant to permit any procedures that may increase the expense or the procedures that may increase the expense or the time required to complete a well. Consequently, suitable cores often are simply not available. Furthermore, only a very few of the petroleum production research laboratories have the facilities production research laboratories have the facilities for measuring interfacial tension, contact angle and relative permeabilities at the elevated temperatures and pressures normally encountered in reservoirs.

The following study provides, for the first time, relative permeability data obtained with fresh, preserved cores and reservoir fluids at reservoir preserved cores and reservoir fluids at reservoir pressure and temperature. Measurements were also pressure and temperature. Measurements were also made routinely with refined fluids and extracted cores to afford comparisons. Advancing and receding contact angles were measured as a function of time with the actual reservoir fluids on a solid surface representative of the reservoir rock to characterize the wetting equilibrium during the tests. Finally, a procedure was devised which, for the extracted procedure was devised which, for the extracted cores, yielded the original set of relative permeability curves. permeability curves.
Mathematical Simulation of Polymer Flooding in Complex Reservoirs
Authors: Bondor P.L. , Hirasaki G.J. , Tham M.J.
Published: December 2007

Simulation of polymer flooding in many complex reservoirs has requirements that preclude the use of either three-phase stream tube or two-phase finite-difference simulators. The development of a polymer flooding model used in a three-phase, polymer flooding model used in a three-phase, four-component, compressible, finite-difference reservoir simulator that allows the simulation of a variety of complex situations is discussed.

The polymer model represents the polymer solution as a fourth component that is included in the aqueous phase and is fully miscible with it. Adsorption of polymer is represented, as is both (1) the resulting permeability reduction of the aqueous phase and (2) the resulting lag of the polymer injection front and generation of a stripped polymer injection front and generation of a stripped water bank. The effects of fingering between the water and polymer are taken into account using an empirical "mixing parameter" model.

The resulting simulator is capable of modeling reservoirs with nonuniform dip, multiple zones, desaturated zones, gravity segregation, and irregular well spacing and reservoir shape.

Two examples are presented. The first illustrates the polymer flooding of a multizone dipping reservoir with a desaturated zone due to gravity drainage. The second illustrates the flooding of a reservoir with a gas cap and an oil rim with polymer injection near the oil-water contact. In this example, the effects of nonuniform dip, irregular well spacing and field shape, and gravity segregation of the flow are all taken into account. The two examples presented illustrate the versatility of the simulator presented illustrate the versatility of the simulator and its applicability to a wide range of problems.

Introduction

The design of a polymer flood for a complex reservoir requires a model that represents the reservoir features that have a significant effect on the performance of the flood. These features may include the presence of a gas cap or a desaturated zone due to gravity drainage in a dipping formation, the presence of an aquifer, irregular well spacing and reservoir boundaries, multiple zones, reservoir heterogeneities, and a well performance that is limited by state proration, injectivity, and productivity. These reservoir features are being productivity. These reservoir features are being represented by most compressible, three-phase, three-dimensional simulators. However, to model polymer flood projects, it is necessary to include a polymer flood projects, it is necessary to include a conservation equation for the polymer, and to represent the adsorption of polymer, the reduction of be rock permeability to the aqueous phase after contact with the polymer, the dispersion of the polymer slug, and the non-Newtonian flow behavior polymer slug, and the non-Newtonian flow behavior of the polymer solution.
A Rapid Accurate Unsteady-State Klinkenberg Permeameter
Authors: Jones Stanley C.
Published: December 2007

A simple, unsteady-state apparatus and appropriate theory have been developed for measuring the Klinkenberg permeability, Klinkenberg slip factor, and Forchheimer turbulence factor of core plugs. The technique is last and accurate and bas replaced nearly all steady-state gas permeability determinations made in our laboratory. The theory of operation, capabilities and limitations of the apparatus are discussed. New data are presented for more than 100 cores, correlating slip and turbulence factor vs permeability.

Introduction

Permeability is usually measured with air at mean pressures just above 1 atm. This steady-state determination is rapid, but it can lead to serious errors. For example, the low-pressure air permeability of tight core often differs from its permeability of tight core often differs from its permeability to liquid or high-pressure gas by 30 permeability to liquid or high-pressure gas by 30 to 100 percent or more. Correction factors (Klinkenberg slip factors) from correlations are available, but still, the corrected, low-pressure measurement can exhibit considerable error.

These errors are avoided by determining gas permeabilities at two or three mean pressures such permeabilities at two or three mean pressures such as 25, 50 and 100 psi, and then extrapolating to infinite pressure to obtain the equivalent liquid or Klinkenberg permeability. This method is generally reliable, but has two drawbacks it requires tedious rate measurements with a soap bubbler or other device, and the back-pressured flow system requires several minutes to reach steady state. Typical throughputs are 8 to 12 cores per day.

The desire to estimate accurately the injectivity into secondary and tertiary oil recovery prospects and to find the deliverability of very tight gas reservoirs has created a growing demand for reliable Klinkenberg permeability determinations in our laboratory. This demand made clear the need for a more rapid, yet accurate permeameter. On the premise that pressure measurements are made more premise that pressure measurements are made more conveniently and accurately than rate determinations, we developed a permeameter in which both rate and pressure drop across a core can be derived from pressure drop across a core can be derived from pressure measurements alone. The resulting pressure measurements alone. The resulting unsteady-state instrument is fast and accurate.

Transient permeability techniques have been discussed and other unsteady-state permeameters have been built and reported, but to our knowledge the instrument described herein is the only practical one for routine measurement of Klinkenberg permeability that does not require an empirical permeability that does not require an empirical correlation using cores of known permeability to construct calibration curves. It is also the only one from which Klinkenberg permeability, Klinkenberg slip factor and Forchheimer turbulence factor can be determined from a single run.
On Determining the Continuous Phase in Microemulsions
Authors: Dreher K.D. , Sydansk R.D.
Published: December 2007

In light of recent advances in the use of micellar solutions (microemulsions) in oil recovery and well stimulation, it has become important to define accurately the physical properties of these systems. One aspect of such work is to distinguish between the disperse phase and the continuous phase, particularly at extreme concentrations of either water or hydrocarbon. Conventional techniques for making this distinction include the dye solubility method, the phase dilution method, the conductivity method, and the fluorescence method. However, a single test may give ambiguous results. We shall present here viscosity, conductivity, and miscibility data for a series of micellar solutions that are comparable in composition with those applied in the field.

Example 1 shows data obtained with a micellar solution prepared with a 420 equivalent weight (eq. wt.) petroleum sulfonate (of our own manufacture) to which was added 1-pentanol to produce a single-phase, optically clear system. Both conductivity and miscibility data indicate phase inversion between 2.2 and 2.3 volume percent 1-pentanol. Further, the data show that the inversion was from oil-external to water-external as the amount of 1-pentanol in the system increased. Continued addition of this cosurfactant (2.6 volume percent) led to separation of an aqueous phase. percent) led to separation of an aqueous phase. This observation is similar to those made by Winsor and Bowcott and Schulman, in that a system with the characteristics of a water-external micellar solution can exist in equilibrium with excess aqueous phase. Most of the brine had been expelled from the micellar solution, at 3 volume percent 1-pentanol. At this point, the conductivity decreased markedly; and the point, the conductivity decreased markedly; and the remaining micellar solution became miscible with hydrocarbon.

Example 2 shows data obtained with the same petroleum sulfonate and cosurfactant. However, in petroleum sulfonate and cosurfactant. However, in this case the micellar solution contained 70 weight percent brine as opposed to 30 weight percent of percent brine as opposed to 30 weight percent of Example 1. No evidence of phase inversion is present over the single-phase region, and both conductivity and miscibility data indicate a water-external system.

Example 3 shows the results obtained with a micellar solution prepared with a 470 equivalent weight petroleum sulfonate (commercially available).
Relative Permeabilities From Displacement Experiments With Full Account for Capillary Pressure
Authors: Helset H. M. , Nordtvedt J. E. , Skjœveland S. M. , Virnovsky G. A.
Published: December 2007

Relative permeabilities are important characteristics of multiphase flow in porous media. Displacement experiments for relative permeabilities are frequently interpreted by the Johnson-BosslerNaumann method neglecting capillary pressure. The experiments are therefore conducted at high flooding rates, which tend to be much higher than those experienced during reservoir exploitation. Another disadvantage is that the relative permeabilities only can be determined for the usually small saturation interval outside the shock. We present a method to interpret displacement experiments with the capillary pressure included, using in-situ measurements of saturations and phase pressures. The experiments can then be run at low flow rates, and relative permeabilities can be determined for all saturations. The method is demonstrated by using simulated input data.
Challenges With Jointed-Pipe Underbalanced Operations
Authors: Saponja Jeff
Published: December 2007

Successful underbalanced operations demand a systematic approach with integration of engineering, operations, production, reservoir, and geology. There are significant advantages to under-balanced drilling (UD). Formation damage can be minimized if proper circulating fluids and operating parameters are chosen; there is an opportunity for reservoir evaluation and characterization while drilling; lost circulation and differential sticking can be avoided, combined with improvements in drilling rate of penetration (ROP); and it also provides an alternative method of well control.

This paper discusses engineering challenges and considerations for underbalanced operations using multiphase flow as well as advances made during UD with rotary jointed pipe. Excluding air, mist, and foam, underbalanced techniques with multiphase fluids are reviewed. Much of the discussion and concepts also apply to coiled-tubing underbalanced operations.
Measurement of Resistance to Flow of Fluids in Natural Gas Wells
Authors: Smith R.V. , Williams R.H. , Dewees E.J.
Published: December 2007

Transmission factors for the flow strings of gas wells were determined by tests on wells in six fields of Oklahoma, Texas, and Louisiana. Data were collected on 14 gas wells while gas was flowing through 1¼, 2, 2½, and 3-in. tubing and 5½ and 7-in. casing. The transmission factors developed from these data were found to follow the resistance equation published by Nikuradse for turbulent flow in "rough" pipes with an average absolute roughness of 0.000,65 in. This average absolute roughness is believed to be representative generally of the flow strings of gas wells with the exception of those that have been exposed to corrosion or other conditions causing undue roughness. Also, use of an absolute roughness of 0.000,65 in. probably will result in transmission factors that are more representative of gas-well conditions than those in common use today, provided that the transmission factors are calculated by the methods outlined in this report. The authors believe that use of these transmission factors will permit calculation of more accurate subsurface pressures in gas wells than those in use today.

Introduction

Engineers use transmission factors in flow equations to compute subsurface pressures in flowing gas wells from measured wellhead pressures. These subsurface pressures are necessary for determining the productivity of gas wells from "back-pressure" tests. The methods of calculating pressures in flowing gas wells, as outlined by Rawlins and Schellhardt in Bureau of Mines Monograph 7, are based on the transmission factors in the well-known Weymouth formula. Natural gas engineers have realized that errors introduced by using transmission factors as given by the Weymouth formula are relatively unimportant in testing low-capacity gas wells; but they also know that such factors are important considerations in testing large-capacity wells. Accordingly, the research described in this report was undertaken to fulfill the need for more accurate means of calculating subsurface pressures in gas wells.

This report is part of the Bureau's study of the flow of natural gas through pipe and commercial pipelines. Several of the conclusions regarding flow in the flow strings of gas wells were influenced by the results of the study of flow in horizontal pipelines. These instances are mentioned in the text of this report.
Coping with Nature Offshore An SPE-AIME Distinguished Lecture
Authors: Blenkarn Kenneth A.
Published: December 2007

Introduction

The distinguishing feature of development for offshore petroleum is the need to provide a dry, stable working space from which personnel can operate in the conduct of conventional petroleum drilling and production. The industry has devoted substantial production. The industry has devoted substantial effort and money to meet the need for working platforms, in the form of either fixed or floating platforms, in the form of either fixed or floating structures. The design of these structures obviously requites expertise in structural engineering. Moreover, there is an accompanying need for competence in oceanography to understand the environmental forces in the ocean. Both structural engineering and oceanography are outside the traditional petroleum or mining engineering activity. Nevertheless, the offshore industry must employ, and in many cases contribute to advancements in, these technologies. Consequently, petroleum engineers are increasingly being called upon to direct work in these unfamiliar subjects. This conceptual introduction to offshore structures and the governing ocean environment is directed at those engineers.

Fixed Platforms

The basic element of offshore development is the fixed, bottom-supported structure or platform. While some platforms afford only minimal walkway area around a single well, many platforms support all the equipment and needs for both the drilling and the production operations. Early offshore platforms were production operations. Early offshore platforms were ordinarily pile-supported piers, such as are commonly observed in harbor installations. However, to meet the special needs of the offshore conditions, the industry has developed a "template" or "jacket-type" structure. There are three distinct components to these structures: the jacket itself, the piling, and the deck structure. The cross-braced jacket must extend from the ocean floor to above the water surface. It is generally assembled from tubular structural members in a fabrication yard. Subsequently, the jacket is moved onto a barge and transported to the off shore location. There it is launched or lifted into the water for placement at the prescribed site. (See Fig. 1.) Once the jacket is prescribed site. (See Fig. 1.) Once the jacket is in place, piling are lowered down through the tubular legs of the jacket and driven or otherwise installed deep into the ocean floor. The jacket and piling are then secured together, and the deck is raised to rest on top of the piles. (See Fig. 2.) Platform concepts and installation are discussed in Refs. 1 and 2. To install offshore platforms, which are very large structures, special construction equipment is necessary. Most impressive is the fleet of derrick barges serving mainly the offshore industry.

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P. 257
Buy, Build, Beg or Borrow: Delivering Applications in the New Age of Software Development
Authors: Little Todd , Webb Steve
Published: December 2007

In the last decade, changes in the oil and computer industries have complicated the process of delivering software applications significantly. Although the oil industry has gone through extensive downsizing, computing advances have forced users to demand more complete and integrated computing solutions. Several oil companies responded to this problem with a policy of "buy, don't build." Although useful, this mindset does not address directly the real question of how to maximize and leverage limited resources to deliver the necessary applications to the user community efficiently. This paper delves beyond the bipolar buy vs. build question to present experiences with various approaches that have been used for delivering software. Among the methods we discuss are software tools, research institutions, vendor consortium projects, alliances, and industry standards.
Reservoir Simulation: Past, Present, and Future
Authors: Watts J. W.
Published: December 2007

Reservoir simulation is a mature technology; simulation results guide most major reservoir-development decisions in some way. Despite this maturity, the technology is changing rapidly, and both providers and users of reservoir simulation software must understand the future of these changes. This paper takes a long-term view of reservoir simulation, describing where it has been and where it is now. It closes with a prediction of what the reservoir simulation state of the art will be in 2007 and speculation regarding certain aspects of simulation in 2017.
Big Mineral Field Exploitation - A Challenge to Engineers
Authors: Garlick J.M.
Published: December 2007

Exploitation of the Big Mineral field, located in North Central Texas, has been and continues to be a challenge to the engineer. The field is partially inundated by the waters of Lake Texoma. Multizone oil production ranging in depth from 3,600 to 10,200 ft is found in steeply dipping Pennsylvanian and Ordovician sediments. This paper brings into sharp focus the contributions of each branch of engineering to the solution of the major development and production problems.

Based on comprehensive data gathered on early development wells, it was determined that the drilling of separate wells to each of six production horizons was justifiable. To accommodate wells drilled in the lake bed 32 earthen drilling platforms with earthen access roadways were planned and constructed. Each platform was of sufficient size to allow the drilling of from one to three wells. In order to combat crooked hole conditions and stimulate drilling rates "large size drill collars" and "jet bit" programs were followed. Hydraulic artificial lifting methods, remote control of flowing wells, and semi-automatic centralized storage facilities were provided so that production would not be interrupted should the earthen platforms be inundated by the lake.

Introduction

As in most industries management in the petroleum industry is relying more and more upon engineers to plan development and production projects. Where in the early days perhaps one engineer handled all engineering problems, companies now employ a staff of 10 or more engineers, each with a different engineering background and responsible for a specific phase of engineering. It therefore follows that if an integrated engineering plan is to be accomplished, all of these engineers must be consulted, work together in an atmosphere of understanding, and contribute their part to the master plan. This paper has been written for the purpose of showing how these principles have been applied to the variety of problems involved in the exploitation of the Big Mineral field. Consequently, no attempt is made to present a complete history of the field. Instead, only the major problems are highlighted. Special emphasis is placed on each engineer's contribution to the solution of these problems.
Variable Flow Rate Reservoir Limit Testing (includes associated paper 4262 )
Authors: Earlougher Robert C.
Published: December 2007

With this technique, reservoir size can be estimated from pressure data taken from either production or injection wells operating on a cyclic rate schedule. So long as the requirement is satisfied that the flow rate vary cyclically rather than increasing or decreasing montonically, reservoir limit testing is quite simple and an engineer can accomplish it without computer aid.

Introduction

The conventional reservoir limit test1-4can be used to estimate reservoir size if the test well operates at a constant flow rate during the test. Unfortunately, it is not always feasible to perform a test at a constant rate, at least for more than a few hours. This is particularly true when flow rate varies cyclically as in oil wells that are pumped cylically, water supply wells, and waste-disposal wells.

This paper shows how to estimate reservoir size from pressure data in wells operating with a cyclic rate schedule. The method applies to both injection and production wells. The important requirement is the cyclic rate: rate must oscillate about a mean value within some relatively regular period. When this condition is satisfied, reservoir limit testing is fairly simple. This requirement can be relaxed, in which case there will be a corresponding reduction in the accuracy of the calculated result. This is an important consideration when the engineer has no control over the quality of data - for instance, when the engineer has several years of historical data from a well. If he knows only rate and pressure at several points in time, he cannot apply a very accurate, sophisticated analysis technique. The method of this paper allows him to estimate reservoir size from such data, although the accuracy may be less than desired. This method should not be used if a better approach is available. Its value lies in providing reasonable engineering estimates when conditions prevent testing and analysis under more ideal conditions.

We shall present here a theoretically sound reservoir limit testing procedure for a cyclic two-flow-rate situation. Simulated pressure-time data for more complicated rate schedules experimentally extend the analysis technique to more realistic situations. The analysis techniques and suggestions for its use are presented, and an example using data from an existing industrial waste-disposal well, is included for illustration.

Reservoir Limit Test Analysis

The familiar reservoir limit test1–4 requires that a well be operated at constant rate until pseudosteady-state-flow conditions have existed for some time. Then, reservoir size can be calculated fromEquation 1

where: q=flow rate for the well, STB/D

q>0 for production, q<0 for injection

m*=slope of the linear portion of the pressure vs flowing-time plot, psi/hr

The slope, m*, is the constant rate of pressure change during pseudosteady-state flow; m* is negative for production, positive for injection.
Asphaltenes, Water Films, and Wettability Reversal
Authors: Kaminsky R. , Radke C. J.
Published: December 2007

We present a transport model for asphaltene diffusion from an oil/water interface through a water film followed by adsorption at a solid/water interface. Using a Langmuir adsorption isotherm, the effects of asphaltene aqueous solubility and adsorption constant K on equilibration time are established. For K greater than 1 nm and for asphaltene solubilities down to 0.1 ppb, adsorption equilibrium, taken to be 1 mg/m2, occurs within a few hours. Negligible asphaltene solubility does not explain why a water film prevents asphaltene adsorption and wettability alteration in reservoir rock.
Lignosulfonate Stabilized Emulsions in Oil Well Drilling Fluids
Authors: Browning W.C.
Published: December 2007

Oil in water emulsions have become important in oil well drilling fluids. Lignosulfonates, prominent among various stabilizing agents, have been used successfully for several years in both lime-base and brine-based fluids. This paper is concerned with the surface active properties of the lignosulfonates, the characteristics of lignosulfonate stabilized emulsions, and their application to oil well drilling.

Lignosulfonates in solution may be regarded as subcolloidal, high molecular weight polyelectroyltes. They do not possess the hydrophobic-hydrophilic molecular structure or other attributes of the McBain "colloidal electrolyte." In general, lignosulfonates are not effective in lowering surface or interfacial tension of water solutions, but certain sodium lignosulfonates when used in combination with alkaline brines may lower interfacial tension.

Lignosulfonates stabilize emulsions because the lignosulfonate molecule is adsorbed at the oil-water interface, establishing a high order electrokinetic charge and also a semi-rigid film. Lignosulfonate stabilized emulsions are stable in high concentrations of inorganic electrolytes, stable to heat, freezing, and to mechanical action.

Drilling fluids with lignosulfonate stabilized emulsions may be prepared to control water loss independent of bentonite or organic colloids such as starch. Such fluids may possess low viscosity, low weight, and low water loss simultaneously. These fluids have low mud-making properties and are unaffected by the usual inorganic contaminants, yet if desired may be adjusted to raise viscosity and gel to form high weight muds.

A more complete understanding of the lignosulfonate and their potentialities may well aid in the development of drilling fluids designed to cope with certain of the many problems encountered in oil well drilling.

Introduction

Emulsion muds may be defined as water-base drilling fluids to which oil had been added and subsequently emulsified. These muds are relatively new to oil well drilling, the literature being rather meager until about 1949. Field use in recent years has brought emulsion muds into prominence as important and useful drilling fluids, but full knowledge of their potentialities is yet to be realized.
A New Tool for Perforating Casing Below Tubing
Authors: Caldwell Blake M. , Owen Harrold D.
Published: December 2007

The continued use of permanent-type well completion has pointed up the need for more powerful through-tubing perforating equipment. A new expendable shaped charge perforator has been developed in which the charges are run through the tubing in a vertical position and then opened out to a horizontal position when at the desired shooting zone. The performance of this new tool is comparable to that of conventional casing type perforators.

This paper describes the new tool and its applications. Performance data in targets and under various actual well conditions are presented.

Introduction

The general acceptance and increasing use of permanent-type well completion by the oil industry has indicated the need for through-tubing perforating equipment with performance comparable to that of conventional casing type perforators. To achieve the performance desired, a new, expendable, shaped charge perforator has been developed with adequate power for effectively perforating both 51/2 -in. and 7-in. casing below tubing. This has been accomplished without resulting severe damage to the casing and can be obtained under extremes of pressure and temperature. The design of this new tool is a radical departure from previous concepts of tubing guns since it was felt that the two major limitations imposed by previous designs severely handicapped performance.

The first of these limitations was the restriction imposed upon the length of the charges by the necessary small inside diameter of the carrier. This resulted from the necessity for compromises in designing a hermetically sealed gun small enough to allow free passage through 2-in. tubing, yet with sufficient wall thickness to withstand some minimum pressure. In an effort to overcome this limitation, the charges were in some cases placed at an angle with the axis of the well with resulting loss in effective depth of penetration.
Scheduling Gas Field Production for Maximum Profit
Authors: Huppler John D.
Published: December 2007

A mathematical procedure for finding the most profitable gas field production policy to meet a gas profitable gas field production policy to meet a gas sales contract has been developed. Results indicate profits can be increased through combinations of profits can be increased through combinations of earlier liquids production, increased gas recovery, and investment reduction. The optimal plan for operating a gas field is found by applying nonlinear programming to the over-all problem o production programming to the over-all problem o production rate scheduling. Risk is accounted for by specifying that any investment yield some minimum incremental profit-to-investment ratio. Computed results, an profit-to-investment ratio. Computed results, an illustrated by several example problems, include average and peak production rate schedules for each reservoir, well-drilling schedules in each reservoirs, a list of recompletions, and compression purchases for the field. Compression can be assigned purchases for the field. Compression can be assigned to each reservoir or it can be pooled in the field. Dynamic programming is used to find the best investment schedule in each reservoir. Each gas reservoir is assumed to have a uniform pressure distribution throughout. Water influx is described by the van Everdingen-Hurst analytic solution for a radial aquifer. In each reservoir, one set of gas-well deliverability curves for production to four delivery pressures is employed, and in-place facilities are always operated to minimize compression requirements.

The Single-Reservoir Problem

We shall solve the following optimization problem for a single gas reservoir: Given a desired gas delivery schedule and a specified peak delivery capability, find the optimal schedule for drilling new wells, the optimal plan for installing compressor horsepower, a detailed operating plan, and the total discounted profit for the best policy. We make the following assumptions in the analysis. 1. Pressure is uniform throughout the reservoir. This implies that well location is immaterial. 2. A single set of well deliverability curves is adequate. 3. The unsteady-state water influx equations satisfactorily describe aquifer behavior. 4. The optimum policy can be broken into two stages. In the first period, desired peak delivery capability is maintained through the addition of wells and compressive horsepower In the second period no new wells are drilled and no compression period no new wells are drilled and no compression is added; the reservoir flow rate declines.
Unsteady-State Pressure Distributions Created by a Well With a Single Infinite-Conductivity Vertical Fracture
Authors: Gringarten Alain C. , Ramey Henry J. , Raghavan R.
Published: December 2007

Introduction

During the last few years, there has been an explostion of information in the field of well-test analysis. Because of increased physical understanding of transient fluid flow, it is possible to analyze the entire pressure history of a well test, not just long-time data as in conventional analysis.1 It is now often possible to specify the time of beginning of the correct semilog straight line and determine whether the correct straight lie has been properly identified. It is also possible to identify wellbore storage effects, and the nature of wellbore stimulation as to permeability improvement, or fracturing, and to quantitatively analyze those effects.

Such accomplishments have been augmented by attempts to understand the short-time pressure data from well testing - data that were often classified as too complex for analysis. One recent study of short-time pressure behavior2 showed that it was important to specify the physical nature of the stimulation in considering the behavior of a stimulated well. That is, stating that the van Everdingen-Hurst infinitesimal skin effect was negative was not sufficient to define short-time well behavior. For instance, acidized (but not acid-fractured) and hydraulically fractured wells might not necessarily exhibit the same behavior at early times, even though they could possess the same value of negative skin effect.

In the same manner, hydraulic fracturing leading to horizontal or vertical fractures could produce the same skin effect, but with possibly different short-time pressure data. This could then provide a way to determine the orientation of fractures created by this type of well stimulation. In fact, it is generally agreed that hydraulic fracturing usually results in one vertical fracture, the plane of which includes the wellbore. Most studies of the flow behavior for a fractured well consider vertical fractures only.3–11

Yet it is also agreed that horizontal fractures could occur in shallow formations. Furthermore, it would appear that notch-fracturing would lead to horizontal fractures. Surprisingly, no detailed study of the horizontal fracture case had been performed until recently.12 A solution to this problem was presented by Gringarten and Ramey.13 In the course of their study, it was found that a large variety of new transient pressure behavior solutions useful in well and reservoir analysis could be constructed from instantaneous Green's functions.14 Possibilities included a well with a single vertical fracture in an infinite reservoir, or at any location in a rectangle.
Fracturing at High Injection Rates, Spraberry Trend Area Field
Authors: Brooks Thomas P. , O'Quinn Percy C. , Life Warner E.
Published: December 2007

The application of relatively large volume fracture treatments using anoil-sand mixture at high injection rates in wells completed in the Spraberryformation has indicated improved drainage from the matrix rock. This isconsidered to result from enlargement of existing open fractures, possibly fromopening of fractures not previously effective, and breaking down existingblockage in the vicinity of the well bore. The results of this type oftreatment as applied to a group of wells in the Spraberry Trend Area field arediscussed with reference to well performance and economics.

Introduction

Extremely small return on investment in a group of wells drilled in theSpraberry Trend Area field called for concerted effort toward stimulation ofproduction. Production history indicated that original recoverable reservefigures were inordinately above ultimate recoveries which could then beforeseen. Many wells were facing abandonment with subsequent writeoff ofreserves if means of restoring them to production were not forthcoming. Otheroperators were experimenting with means of increasing recovery, such as waterimbibition, but results would not be known for some time. Satisfactory resultsachieved from formation fracturing by injecting oil-sand mixture at high ratesin other areas indicated possible results from such treatment in the Spraberryformation. Particular similarity was noted between the Spraberry formation anda reservoir in Wyoming-both having low permeability, vertical fracturing, andinterbedding with shales. Fracturing of the formation in Wyoming using highinjection rates had been and was then being practiced with satisfactoryresults. The decision to apply this fracturing technique experimentally to onewell and the results of this initial treatment have led to numerous wells beingfractured in this manner.
Electrical Conductivities in Shaly Sands-I. The Relation Between Hydrocarbon Saturation and Resistivity Index; II. The Temperature Coefficient Of Electrical Conductivity
Authors: Waxman Monroe H. , Thomas E.C.
Published: December 2007

The Waxman-Smits physical model for describing conductivity in shaly sand has been extended to allow for oil-bearing sand, and the required assumptions have been confirmed by laboratory measurements. A conclusion from the tests is that the effective concentration of clay-exchange cations increases in proportion to the decrease in water saturation. The temperature coefficients of electrical conductivity for a group of shaly sands were measured and these data were treated by the same model.

Introduction

Waxman and Smits have recently advanced a simple physical model describing shaly sand conductivities. physical model describing shaly sand conductivities. The model assumes:a parallel conductance mechanism for free electrolyte and clay-exchange cation components,an exchange cation mobility that increases to a maximum and constant value with increasing equilibrating electrolyte concentration, andidentical geometric conductivity constantsapplicable for the contributions of both the free electrolyte and the clay-exchange cation conductance to the sand conductivity.

The general equation for water-saturated sands is then obtained:(1)

with(2)

Co and Cw are the specific conductances of the sand and equilibrating brine, respectively (mho cm). F* is the shaly sand formation resistivity factor, related to porosity (0) according to an Archie-type relation:(3)

where m* is the porosity exponent. 1/F* is the slope of the straight-line portion of the Co vs Cw, curve. Qv is the effective concentration of clay-exchange cations (equiv/liter or meq/mi) and can be determined independently from the ratio of cation exchange capacity (meq per 100 gm of rock) per unit pore volume of rock (ml per 100 gm of rock). B represents the equivalent conductance of the clay counterions as a function of Cw with units of mho cm2 meq -1. lambda Na (or B max) is the maximum equivalent ionic conductance of the (sodium) exchange ions, and a and lambda are empirical constants. Waxman and Smits report values (Group 1 samples) of a = 0.83, = 0.02, and lambda Na = 38.3 cm2 equiv- 1 ohm-1 at 25 degrees C. Somewhat different values of the a, y, and lambda Na were reported by Waxman and Smits for another and considerably smaller set of shaly sand samples (Group 2). These were a = 0.6, lambda = 0.013, and lambda Na = 46.0 CM2 equiv-1 ohm-1 at 25 degrees C. Further work reported here (Table 2) supports the values obtained for the Group 1 samples. The Qv values calculated from conductivity data and a value of lambda Na = 38.3 cm2 equiv-1 ohm-1 agree within experimental error with Qv values determined by independent laboratory procedures for the new group of shaly sands used for this study.

JPT

P. 213
Offshore Fracture Gradients
Authors: Christman Stan A.
Published: December 2007

The analysis described here, based on Santa Barbara Channel field experience, shows that increasing water depth reduces the overburden stress gradient, substantially influencing the apparent fracture gradient, particularly at shallow penetrations. Two methods of correlating fracture particularly at shallow penetrations. Two methods of correlating fracture gradient are presented in the analysis.

Introduction

The consideration of formation fracture gradients in selecting casing setting depths is fundamental to the preparation of an acceptable drilling program. When preparation of an acceptable drilling program. When Exxon Co. U.S.A. undertook the deepwater challenges of the Santa Barbara Channel, a project was initiated to develop a fracture-gradient prediction technique that would assess the impact of water depth.

Development of the Technique Onshore Fracture Gradients

As frequently referenced, Hubbert and Willis, established a theoretical basis for subsequent work in the development of actual fracture-gradient prediction techniques. Later theoretical studies of porous bodies have concluded that the most important factors affecting fracture initiation pressure are the overburden stress, the formation fluid pressure, and the horizontal-to-vertical stress ratio, whereas rock compressibilities and Poisson's ratio have relatively little influence. Matthews and Kelly, in a technique presented in 1967, correctly indicated that the stress ratio, F sigma, was the most significant and yet elusive variable. The following relation was presented for the fracture gradient:

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

By assuming a total overburden gradient of 1.0 psi/ ft, we can estimate the effective vertical stress as follows:

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

For normally pressured formations, the stress ratio, F sigma, is empirically correlated, on the basis of field data, for a given area as a function of depth. The onshore aspect of the technique that was developed for the Santa Barbara Channel area incorporates these stress-ratio concepts with a method to estimate the actual overburden gradient rather than using the assumed value of 1.0 psi/ft. Since the overburden stress at any depth should be the cumulative weight of the formations above that depth, well data that are indicative of formation density can be used to estimate overburden. Techniques have been published that are based on velocity data from seismic published that are based on velocity data from seismic surveys and sonic logs or that utilize formation bulk density logs directly. We selected the latter method and estimated overburden with Eq. 3:

..........................................(3)

where 0.4335 is the constant used to convert units of gm/cc to psi/ft. In practice, of course, a simple arithmetic average of the bulk densities of the overlaying formations, pb, will suffice:

..........................................(4)

The final form of the fracture-gradient prediction formula used in the Channel is given as Eq. 5:

..........................................(5)

JPT

P. 910
Experimental and Calculated Behavior of Dissolved-Gas-Drive Systems
Authors: Ridings R.L. , Dalton R.L. , Greene H.W. , Kyte J.R. , Naumann V.O.
Published: December 2007

This paper presents a one-dimensional numerical method for calculating dissolved-gas-drive behavior for a single well or a linear reservoir. Pressure and saturation distributions can be calculated, including the effects of capillary and gravity forces. The analysis has been programmed for solution on the IBM 7090 digital computer. A comparison of experimental and calculated behavior for two linear models demonstrates that the method is suitable for calculating dissolved-gas-drive behavior under reservoir conditions of flown Dissolved-gas-drive tests were run, at different production rates and with oils of different viscosities, on short (6-ft) and long (173-ft) flow models. For tests approximating reservoir pressure gradients and flow rates, there was excellent agreement between experimental and calculated results. A series of calculations of well behavior for thin, horizontal, homogeneous, dissolved-gas-drive reservoirs shows that ultimate recovery is independent of production rate or well spacing in such cases. These calculations also show that Muskat's method and similar material-balance analyses are not applicable under some conditionsparticularly for high pressure drawdowns.

Introduction

The problem of calculating dissolved-gas-drive reservoir performance has received a great deal of attention throughout the oil-producing industry for many years. Really significant advances, however, have been made only in recent years. The rapid evolution of high-speed computing equipment and techniques has opened up new approaches to the problem and led to realistic, quantitative analyses free of many of the assumptions and limitations of earlier methods. The one-dimensional numerical method described in this paper includes the effects of both gravity and capillary forces. A number of test calculations, based on different rates, spacings, and rock and fluid properties, have shown that the method is adequate for systems that can be reasonably represented by a one-dimensional model (linear or radial) and in which fluid segregation perpendicular to the direction of flow is not important. Along with the development of mathematical methods, an experimental program was conducted and the data were used to test the validity of the theoretical basis of the mathematical method. Linear models were used and all experiments were run using 1,000-psig bubble-point oils. The use of long, high-pressure models enabled us to more closely approach reservoir gradients and flow rates.

MATHEMATICAL FORMULATION DIFFERENTIAL EQUATIONS

The differential equations describing dissolved-gas-drive behavior in one dimension dare summarized here. They include Darcy's law for flow of oil and gas (Eqs. 1 and 2) and the equations for conservation of mass for oil and gas (Eqs. 3 and 4). The oil and gas pressures are related by capillary pressure (Eq. 5).

vo = - ..........(1)

vg = Rsvo - ......(2)

-qo + ......(3)

-qg + ............................................(4)

SPEJ

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