bluuebunny/crossref_metadata_2025 huggingface dataset:
A Short Cut to Stabilized Gas Well Productivity
Authors: Riley H.G.
Published: December 2007

Here are simplified correlations that quickly provide correction factors for obtaining stabilized productivity from short-term flow tests. The only data needed to use the correlations are reservoir pressure, duration of test, and estimated permeability.

Introduction

For most studies involving gas wells and gas reservoirs, a very important consideration is the stabilized productivity or the ability to deliver gas for a productivity or the ability to deliver gas for a considerable time against a given backpressure. This knowledge is usually most needed in the early stages of development of an area, before extensive well test data or production information can be collected. Even in fields with considerable history, an engineer may frequently need a long-range performance prediction without having access to any data except the short-term test data normally required by state regulatory bodies. Short-term test data typified by a four-point back pressure with only 1 or 2 hours' flow on a point, or pressure with only 1 or 2 hours' flow on a point, or even a one-point 24-hour test may be grossly in error in low permeability reservoirs. Much of our nation's gas reserves is contained in the San Juan, Anadarko and Arkoma basins, which have the common characteristic of low permeability. In these areas it is not at all unusual for a well to require 30 days' flowing time to reach stabilization. Use of short-term test data for such wells would obviously lead to poor-quality estimates of either producing rates or reserves. The long-term flow test, to actually achieve stable flow, may be impractical for any of several reasons. The next best alternative would probably be two-rate flow tests. These require collection of detailed and closely controlled test data and can be costly even though much less time-consuming than the long-term flow to stable conditions. Another possible approach would be to determine interwell permeability and a skin factor from a pressure buildup test. Substitution of these factors with estimates of other reservoir parameters in the Darcy steady-state flow equation parameters in the Darcy steady-state flow equation would provide a reasonable estimate of stable flow capacity. In the absence of adequate field test data to define stabilized producing capacity, a stabilization factor to apply to short-term flow data would be useful; and that is the subject of this paper. For a stabilization factor to be most useful, it should be determinable with a minimum of field test data and calculation and still retain a reasonable degree of accuracy. Correlations have been developed that fulfill the requirement of minimum data and calculation. A check of the correlations with test data from several fields indicates a fair degree of accuracy.

Basis for Correlations The well known Darcy steady-state flow equation neglecting turbulence may be written for gas wells as follows:

(1)

This equation and all others here are in practical field units and the terms are in the nomenclature. In the equation s is the skin factor defined by van Everdingen.

JPT

P. 537
Trends in Geoscience Data Exchange
Authors: Guthery Scott B.
Published: December 2007

Most of the data archive and exchange formats developed in the early days of oil-patch computing are running out of steam. Higher data volumes, greater data complexity, and demands for multidis-cipline and real-time data exchange have positioned data exchange as a key ingredient of today's computing architectures. This article reviews the history of geoscience data exchange and examines some current requirements and standards efforts.
Expert Systems: A 5-Year Perspective
Authors: MacAllister D. J. , Day Ron , McCormack M. D.
Published: December 2007

This paper gives an overview of a major integrated oil company's experience with artificial intelligence (AI) over the last 5 years, with an emphasis on expert systems. We chronicle the development of an AI group, including details on development tool selection, project selection strategies, potential pitfalls, and descriptions of several completed expert systems. Small expert systems produced by teams of petroleum technology experts and experienced expert system developers that are focused in well-defined technical areas have produced substantial benefits and accelerated petroleum technology transfer.
A Field Demonstration of Sour Produced-Water Remediation by Microbial Treatment
Authors: Sublette K. L. , Morse D. E. , Raterman K. T.
Published: December 2007

The potential for detoxification and deodorization of sour produced waters by microbial treatment was evaluated under field conditions. A sulfide-tolerant strain of the chemautotroph and facultative anaerobe Thiobacillus denitrificans was introduced into an oil-skimming pit of the lease automatic custody transfer (LACT) Unit 10 at the Salt Creek field in Wyoming. Field produced water enters this pit from the oil/water separation treatment train at an average flow rate of 5,000 B/D with a potential maximum of 98,000 B/D. Water conditions at the pit inlet are 4,800 mg/L total dissolved solids (TDS), 100 mg/L sulfide, pH 7.8, and 107°F. An aqueous solution of ammonium nitrate and diphosphorous pentoxide was added to this water to provide required nutrients for the bacteria. The first 20% of the pit was aerated to a maximum depth of 5 ft [1.5 m] to facilitate the aerobic oxidation of sulfide. No provisions for pH control or biomass recovery and recycle were made.

Pilot operations were initiated in Oct. 1992 with the inoculation of the 19,000-bbl pit with 40 lbm of dry-weight biomass. After a brief acclimation period, a nearly constant mass flux of 175 lbm/D sulfide was established to the pit. Bio-oxidation of sulfide to elemental sulfur and sulfate was immediate and complete. Subsequent pilot operations focused on process optimization and process sensitivity to system upsets. The process appeared most sensitive to large variations in sulfide loading owing to maximum water discharge events. However, recoveries from such events could be accomplished within hours.

This paper details all pertinent aspects of pilot operation, performance, and economics. From this evidence, the oxidation of inorganic sulfides by T. denitrificans appears to represent a viable concept for the treatment of sour water coproduced with oil and gas.
Pigging Dynamics in Two-Phase Flow Pipelines: Experiment and Modeling
Authors: Minami Kazuioshi , Shoham Ovadia
Published: December 2007

Standard design procedures for two-phase pipelines subject to pigging operation still rely on steady-state methods. Because the flow behavior under a pigging operation is transient, more rigorous methods must be developed for a proper design of such operations. This paper presents an experimental and theoretical study on transient pigging operation.

An extensive experimental program was carried out to acquire two-phase transient flow and pigging data on a 420-m- [1,378-ft-] long, 77.9-mm- [3.068-in.-] diameter horizontal pipeline. A computer-based data-acquisition system was used to obtain detailed information of the flow behavior during the experimental runs. The data include measurements of the time variation of the liquid slug size ahead of the pig, flow rates during the slug delivery, pig velocity, and pressure and liquid holdup distributions. The data were acquired at four measurement stations installed along the pipeline.

A pigging model was developed for predicting the dynamics of a pigging operation. The model incorporates an improved simplified transient model that has been validated with the experimental data. A mixed Eulerean-Lagrangean approach was used to couple the transient model and the pigging model. The resulting computer simulator can predict the transient two-phase flow in a pipeline with or without pigging.
Engineering Document Enhancement Program Improves Facilities Specifications
Authors: Sargent G.L. , LaGrone K.B. , Wong Roy
Published: December 2007

In 1990, the Engineering Document Enhancement Program (EDEP) project was initiated to improve the engineering guidelines used to prepare specifications for E&P facilities projects. The EDEP project mission was to assemble technical writing teams made up of facilities engineers from locations worldwide to create new engineering guides. After 2 years, new guides, plus 65 engineering tutorials and applicable industry standards, on CD-ROM are now available to engineers from their workstation desktops. The new system, also named EDEP, is globally implemented, ensuring that the construction of new E&P facilities are uniform in design; meet operating, safety, and environmental requirements; and are constructed at a lower cost.

Introduction

The E&P divisions use roughly 180 guides for preparing engineering specifications for oil and gas facilities. Traditionally, most of the specifications used were based on downstream and North Sea operations and required extensive modifications to meet local E&P requirements. In 1990, EDEP was initiated to update the engineering specification modification process by revising existing guides, creating new guides and associated data sheets, creating engineering tutorials, and cross-referencing industry standards. The EDEP software runs on UNIX-based workstations, giving engineers fingertip access to a complete on-line library of technical information.

Technical writing teams updated 151 of 180 EDEP guides. This required about 12 man-years of effort by technical specialists-about 22 writing teams per quarter for seven quarters. The remaining 29 guides taken from downstream operations were included in EDEP on an "as-is" basis and converted to electronic format. The project lasted 2 1/2years, from Jan. 1991 through June 1993, and cost roughly $6.9 million.

Guide System Design

The EDEP team consulted other companies to investigate solutions, rather than developing the entire guide system from scratch. Amoco Production Co.'s Engineering Specification Automation System (ESAS) was found to match EDEP's requirements closely and was purchased, with plans to revise it to meet any unique requirements. Much of the terminology, formatting, and linking for EDEP was derived from ESAS.

Similarly, the 28-module Facility Book ware Series was purchased from the Intl. Human Resource Development Corp. to create some of the engineering tutorials. These "off-the-shelf "tutorials were revised by Paragon Engineering Services and edited by company specialists before conversion into electronic format. Additionally, 37 tutorials on topics such as subsea, heavy oil, and noise control were written.
Interfacial Tension of Nitrogen/Volatile Oil Systems
Authors: Huijgens R. J. M. , Hagoort J.
Published: December 2007

This paper presents interfacial tension (IFT) measurements of a nitrogen/volatile oil system at conditions that are typical for North-Sea oil reservoirs. The volatile oil is a well-defined three-component oil, which can be displaced by nitrogen in a developed miscible manner.

Using the pendant drop method, we have measured the IFT of the nitrogen/volatile oil system at four characteristic compositions at a constant temperature of 100°C and in the pressure range of 30 MPa to 40 MPa. For the analysis of the pendant drops we have used advanced image processing techniques. Depending on composition and pressure, we have measured IFTs as low as 0.05 mN/m with an accuracy less than 2%.

Predictions of the IFT of our fluid systems with the parachor method and with Lee & Chien's method show large deviations from the experimental values. At near-critical conditions, the nitrogen/volatile oil system behaves in accordance with critical scaling theories.
Economical Development of Small Isolated Fields
Authors: Edwards W. G.
Published: December 2007

U.K. offshore oil supplies could be in decline in 10 years unless new methods and technology are developed to open fields that are uncommercial by conventional methods. Such technology is being developed, and much of it is aimed at pressure boosting subsea step-out fields to improve production rate and recovery over increasing distances to a host platform. This paper is concerned with the development of small isolated fields for which a new platform facility is not justified or where no suitable existing host platform is available.

The isolated-field production system described here comprises a two-stage subsea separator near the subsea well(s) from which production is tied in by flexible flowlines. Oil/water/gas separation is achieved at near atmosphere pressure, allowing safe loading of the "dead" crude into a tanker. The gas is flared at a surface buoy (directly above the separator unit) that also contains power generation and chemical injection facilities. Liquids are pumped to an offshore tanker-loading catenary anchor leg mooring (CALM) buoy, and then to the connected shuttle tanker. Control of the separator system is autonomous based on a programmable logic controller in the subsea control module, with commands and monitoring by an umbilical from a production center on the tanker.
A New Way to Compute Annular Friction Loss
Authors: Kotb A.K.
Published: December 2007

Laminar flow of non-Newtonian fluids through an annular space is frequently encountered in drilling fluid circulation, cementing, formation fracturing, and water and sand control.

Theoretical solutions for various models (Bingham plastic, Power-law, Reiner-Ravlin, Rabinowitsch) describing the behavior of non-Newtonian fluids have been published. However, data have not been released to substantiate the results. Therefore the development of a new equation to compute friction losses in an annular space - and a comparison of the results with those of other equations derived by different approaches - is important.

The nature of non-Newtonian fluids remains controversial. Some authorities believe that the Bingham plastic model best describes all non-Newtonian fluids. Others disagree and think that most non-Newtonian fluids are best described by the Power-law model. Regardless of controversy, the Bingham plastic model is encountered rarely. This model applies more exactly in high-solids drilling fluids. Popularity of saltsaturated and low-solids drilling fluids, oil emulsion, inverted emulsion and oil base muds - as well as aqueous gels and gelled crude oils for hydraulic fracturing - has emphasized a need for the Power-law model.

Further controversy arose when some authorities proposed that the equation for flow of Bingham plastic fluid in a cylindrical pipe could be replaced in the equation by the hydraulic radius to describe flow in the annulus. Others pointed out that even for a simple Newtonian fluid, the substitution of the hydraulic radius in the cylindrical pipe equation would produce erratic results.
Analysis of Some Factors Related to Permissible Horizontal Motions of a Floating Drilling Vessel
Authors: Hansford John E. , Lubinski Arthur
Published: December 2007

Horizontal vessel motions (drift, sway or surge) result in the bending of the drill-string members in the vicinity of the rotary-drive bushing at the vessel and at the blowout preventer close to the sea floor. Allowable horizontal vessel motions are calculated as a function of hookload, using both cumulative fatigue damage and drill-pipe strength as criteria for drilling and for pulling stuck pipe. The presently used rule limiting horizontal vessel motion to 5 percent of water depth is shown to be too restrictive in some cases and too lenient in others.

Introduction

When drilling from a floating vessel, the rotating drill string is subjected to fatigue damage caused by reversing stresses which arise from heave, roll, pitch and horizontal motions of the vessel. In Ref. pitch and horizontal motions of the vessel. In Ref. 1, the effect of drilling-vessel roll and pitch on the cumulative fatigue damage of the kelly and the first joint of drill pipe below the kelly are examined. As a continuation of that investigation, the present study covers the effect of horizontal motions of the vessel on the drill string. Horizontal departure from over the borehole may be oscillatory (sway or surge), static (drift), or most often, some combination of the two. An accepted limit of horizontal vessel motion of 5 percent of the water depth has been suggested mad percent of the water depth has been suggested mad frequently followed. In reality, the allowable motion is strongly influenced by the hookload. Motions greater than 5 percent of water depth are often permissible, and under some conditions, motions permissible, and under some conditions, motions should be limited to less than 5 percent of water depth. The purpose of this paper is to suggest maximum permissible motions imposed by drill-pipe fatigue damage and pipe strength, as a function of hookload.

IDEALIZED SYSTEMS

Fig. 1 shows an idealized system, highly exaggerated for explicitness. Although pipe bends are shown quite acute, bending stresses were properly defined mathematically. The pipe bending properly defined mathematically. The pipe bending at the rotary-drive bushing (labeled RDB in Fig. 1) is relieved in most cases by a gimbaled bushing and largely taken by the kelly, a more durable member. Therefore, the point of most severe damage is in the area of the blowout preventer rams (labeled BOP).

SPEJ

P. 229
Velocities of Compressional and Shear Waves in Zeolites: Heulandite and Stilbite
Authors: Limur A.
Published: December 2007

In recent years, an increasing number of sedimentary rocks have been reported to contain zeolite minerals among their constituents. Due to their lower densities, zeolites interfere with the density log; hence, whenever their presence is recognized, proper corrections are made in the evaluation of porosity from the density log. Study of a similar question about the effect of zeolites in the evaluation of porosity from acoustic log measurements requires a knowledge of elastic wave velocities in zeolites. A literature search to find data on elastic wave velocities in zeolites proved fruitless; however, we were able to obtain two hand specimens of zeolites from Iceland. Through X-ray analysis and from optical properties, they were identified as heulandite and stilbite. The specimens were fragile; therefore, for convenience in handling during the measurements, they were cast in clear plastic. Each was machined to expose two opposite and parallel surfaces of about 2.5 cm in diameter in a convenient direction (Z), since the crystal axes could not be identified. In this manner, a heulandite sample of 13.828-mm thickness and a stilbite sample of 22.327-mm thickness were obtained for velocity measurements. To measure velocities of the compressional waves, these samples were placed between a pair of compressional wave transducers (280 kHz resonant frequency) in contact with the exposed surfaces. The travel times of the compressional wave pulses in the Z direction were measured by the ultrasonic measurement apparatus described in Ref. 2. The compressional velocities, obtained within 0.5 percent, are listed in Table 1. Heulandite and stilbite are known to have monoclinic structures;, therefore, they are expected to have velocity anisotropy, Since the samples were cast in epoxy, we could not obtain velocity information in the directions other than Z due to problems in mechanical handling of the samples. We were able, however, to obtain indications of anisotropy by changing orientation of the vibration direction of the shear waves.

P. 1099
Selective Matrix Acidizing of Horizontal Wells
Authors: da Motta E. P. , Hill A. D. , Sepehrnoori Kamy
Published: December 2007

The PI of a horizontal well in an anisotropic medium is calculated during a process of partial acidization, in which damage removal occurs over only a fraction of the well length. Two numerical simulators are used in this work: an acidizing simulator, which calculates the permeability distribution around the wellbore; and a reservoir simulator, which calculates the PI of the well. By applying mathematical transformations, it is possible to reduce the acidizing model from a 2D to a 1D problem.

By comparing treatment results, it is possible to select the optimal volume of acid, injection rate, and fraction of the length to be acidized for each well. The same procedure also may be applied for vertical wells both with and without anisotropy.

Simulation results indicate that the application of a partial acidizing strategy reduces the total amount of acid required for significant improvement in well productivity, substantially reducing the financial, operational, and environmental risks involved in the treatment of a horizontal well. In most cases, the optimal injection rate for sandstone acidizing is the maximum rate that does not fracture the formation.
Adopting Object-Oriented Technology: A Case Study
Authors: Trythall Steve
Published: December 2007

Interest in object orientation has surged in the last couple of years. A considerable number of groups have evaluated the technology; some have produced prototypes, and an increasing number have developed applications. A few groups have built significant applications frameworks, most notably the SPIRIT application framework developed by Shell Services in Houston. There are now nascent attempts to define a standard for object-oriented infrastructures with the Petrotechnical Open Software Corp. (POSC) community.

The Petroleum Science and Technology Inst. (PSTI) was one of the early adopters of this technology within the E&P industry. PSTI has been constructing a basin modeling toolbox using object-oriented technologies for the last 6 years. This paper introduces the techniques, describes our use of the technology within the Hedera project, and outlines our experience of the suitability of the techniques for use within the E&P industry.
Estimation of Well Permeability for Use in Single Phase Gas Reservoir Production Simulation
Authors: Joyner Hagan D.
Published: December 2007

Of all of the reservoir data necessary for use in mathematical reservoir simulation, the permeability value is usually the least known and most difficult to obtain. A previously published correlation has been used in estimating permeability values for wells in a tight, single phase gas reservoir. These values were used in a mathematical model, along with other better known reservoir data, to match past performance and predict future performance of individual wells. predict future performance of individual wells. Reasonably satisfactory results were obtained with a minimum number of runs. Computer time is believed to be considerably less than that which would have been required if the correlation had not been available. There are several occasions when permeability values can be successfully estimated for simulation projects without benefit of individual well core projects without benefit of individual well core analysis or pressure test permeability data. The method described here involved use of a correlation presented as Fig. 2 (see Fig. 1) in paper SPE 1555 by L. E. Harlan. It is a log-log plot of adjusted absolute open flow, times 1,000, divided by initial shut-in tubing pressure squared vs known productive capacity (Keh) pressure squared vs known productive capacity (Keh) for 22 gas wells. The 22 data points are from "skin free" wells in carbonate, sand, and conglomerate reservoirs in four basin areas in the U. S. The paper describes adjusted absolute open flow as a well's calculated wellhead absolute open flow potential based on test data after 1 year of production. Justification for construction and application of the correlation is contained in the paper and will not be discussed here. The correlation was used in this study for estimating productive capacity (Keh) for 25 wells in the 2,033-well Blanco Mesaverde gas field in Northwest New Mexico. Adjusted absolute open flow for the wells was calculated from the New Mexico Oil Conservation Commission deliverability test taken 12 to 24 months after a well was placed on production. Permeability was obtained from the correlation-derived Permeability was obtained from the correlation-derived productive capacity through application of net productive capacity through application of net effective pay for a particular well. In the simulation work, predicted capacity was compared with actual capacity at a particular cumulative production point. For nearly all of the wells modeled, a satisfactory match was achieved without necessity of changing permeability.

P. 1389
Quadrature Solution for Waterflooding of Naturally Fractured Reservoirs
Authors: Civan Faruk
Published: December 2007

An efficient solution for deSwaan's formulation of waterflooding in naturally fractured porous media by the quadrature method is presented. Comparisons of the analytic, finite difference, and quadrature solutions of the unit endpoint mobility ratio problem reveal that the quadrature solutions are more accurate and much more easily obtained than the finite difference solutions. The computational requirements of the nonlinear problem with capillary pressure included are comparable to that of the unit endpoint mobility ratio problem. The proposed mechanism of oil transfer from matrix to fracture indicates that the matrix-to-fracture transfer function is limited to two exponential terms. It is shown that the fracture medium capillary pressure has a small effect while the oil viscosity has a large effect in the oil recovery from naturally fractured reservoirs.
Use of Transient Testing in Reservoir Management
Authors: Kamal M.M. , Freyder D.G. , Murray M.A.,
Published: December 2007

Transient tests can be used throughout the life of the reservoir to manage and to optimize recovery of hydrocarbon fluids. This paper shows applications of various well-testing methods during the exploration, appraisal, and primary and secondary recovery phases of field projects. Single-well tests [e.g., drillstem tests (DST's) and buildup tests] are primarily used during the various stages of field development and primary recovery, whereas multiple-well tests (e.g., interference tests) are most often used during secondary recovery. A clear understanding of the type of information obtained from well tests is essential if this information is to be used properly in managing the reservoir. Examples are the different values of permeabilities calculated from single-vertical-well, horizontal-well, and multiple-well tests; the values of average reservoir pressures; and the double-porosity parameters calculated from tests in naturally fractured reservoirs. The state of the art of testing and measurement tools, acquisition systems, and interpretation methods affects the type of information obtained from well tests and should be considered by the petroleum engineer before results are used. The paper presents information to help the engineer use transient tests properly and to their fullest extent. Field examples are used when appropriate.

Introduction

The main difference between petroleum engineering and most other engineering disciplines is that the systems that petroleum engineers work with are given to them, whereas in other engineering disciplines the engineers design their systems. For example, the car engine is designed by a mechanical engineer and the structure of a building is designed by a civil engineer. Oil and gas fields are not designed or developed by petroleum engineers. They are given to them. As a matter of fact, the biggest challenge petroleum engineers face is to characterize these systems. In this regard, petroleum engineers have the same problem as mining and meteorological engineers and groundwater hydrologists. However, petroleum engineers have the added complexity, which mining and meteorological engineers do not have, of being unable to see the in-situ properties of our systems physically and measure them directly. Therefore, to obtain the physical properties of hydrocarbon-bearing formations, petroleum engineers rely on indirect measurements, such as inferring formation permeability from production data, calculating porosity from a sonic log, or determining the distance to a fault from a buildup test.
Viscometric Determination of the Onset of Asphaltene Flocculation: A Novel Method
Authors: Escobedo Joel , Mansoori G. Ali
Published: December 2007

A new technique for the determination of the onset of asphaltene flocculation has been developed through accurate viscosity measurements of a crude oil being diluted with a precipitating agent (n-pentane, n-heptane, n-nonane). This detection method is based on experimental observations of an increase in the viscosity of a crude oil-asphaltene-precipitating agent suspension in which asphaltene particle aggregation occurs. The key point in this development is the phenomenon of asphaltene flocculation induced by the addition of a n-paraffin hydrocarbon (i.e. n-heptane, n-pentane, n-nonane) to crude oil. The onset of asphaltene flocculation is detected graphically, and its location is enhanced by comparison of the analyte curve with a reference system. The reference system was developed using polar and non-precipitating solvents (i.e. toluene, benzene, THF).
PIERS Timings on Various Parallel Supercomputers
Authors: Keenan Philip T. , Flower Jon
Published: December 2007

A parallel implicit research reservoir simulator (PIERS), designed for experimentation rather than production yet with many of the features of realistic petroleum reservoir models, was made available to us as a test program. This article reports results of timing PIERS on five parallel supercomputers. Graphs illustrate performance as a function of the number of processors for several problem sizes. Results indicate that parallel computation provides substantial speed improvement in reservoir simulator codes. Also, the raw timings provide an interesting comparison of machine performance, though one should remember that they apply directly only to PIERS and may vary with different simulators, compilers, operating systems, and hardware configurations.
Casing-Cost Optimization for Complex Loading Situations
Authors: Roque J. L. , Maidla E. E. , Wagner R. R.
Published: December 2007

Casing can be the single most expensive item of an oil well and, in many cases, can be designed in a cheaper way. We present the optimization procedure, method, and algorithm to minimize cost of a combination casing string. The algorithm is general and can be used with any commercial program, provided a few modifications are made for it to be used as a subroutine. To demonstrate its use, a commercial package (that can handle complex load calculations) is tested and the results confirm the effectiveness of the optimization procedure. We present two complete examples that include cost predictions for multiple combination casing strings by use of an extensive database of price and casing properties for the 9⅝-in. (with 27 different casing types) and the 7-in. casing (with 64 different types). With such a great casing database from which to select, it would be very hard to obtain the cheapest string by trial and error.
Shocks and Bifurcations in Black-Oil Models
Authors: Herrera Ismael
Published: December 2007

Here, it is shown that the ‘traditional’ approach to variable bubble-point problems is not consistent, because it does not incorporate important kinds of shocks that occur in black-oil models. This paper contains an exhaustive analysis of shocks that black-oil models may develop and it is shown that a considerable variety of them may indeed occur; a bifurcation mechanism is also exhibited. Except for the class of shocks described by Buckley-Leverett theory, all other kinds may be developed even if capillary forces are present. Modelers must be aware of these pathologies in order to handle them properly. This paper also supplies a basis for the developement of consistent black-oil models, applicable to variable bubble-point reservoirs. The analysis and results here presented, also contribute to a better understanding of limitations imposed by the simplifying assumptions of black-oil models.
Automatic Lease Operations - Weeks Island Field, La.
Authors: Northern Turner P.
Published: December 2007

Introduction

The upward trend of oil production, which usually amplifies producing problems, combined with a search for improved economic and efficient methods have revealed the possibilities of automatic producing facilities along the Gulf Coast. In 1952 the Gulf Coast District of the Gulf Refining Company's Houston Production Division initiated a plan for testing and appraising various types of automatic lease equipment for use in bay fields and offshore operations. Under this plan a small lease was selected, where operating and flowing conditions are similar to coastal and offshore wells. By such a method the performance of all equipment could be observed and evaluated prior to more complex situations. Gulf's Provost Cyr Unit lease was selected for the installation. It consists of 158.70 acres and is located on the east flank of the Weeks Island field, in Iberia Parish, La. The first well was completed in March, 1950. When the drilling program terminated in January, 1953, production had been established from five wells. The calendar daily allowable for the ninth of June, 1953 was 1,254 bbls. All wells are produced by natural flow through positive chokes at the well-head. Flowing tubing pressures range from 800 psi to 1,800 psi. Two of the wells are producing salt water. API gravity of the crude ranges from 30.9 degrees to 35.0 degrees. Producing equipment on this lease consists of four 1,000 bbl stock tanks, one 500 psi oil and gas separator, two 125 psi oil and gas separators, one emulsion-type heater-treater, and one horizontal precipitator. All are connected with adequate manifolds and piping to serve their specific purpose in production of oil and gas. Electricity is available at the lease from a utility company.

Requirements of Equipment

Basic requirements must be met in order to completely produce a lease automatically. First, some type of tank switcher is necessary which will transfer flow from one tank to another when a predetermined fluid level (full) is reached. The set-up must insure that flow cannot be transferred to tanks either full or on pipeline run. Control must be maintained over the opening and closing of the wells. Wells must be closed in when:no tank space is available,a well is produced on a pre-determined schedule, ora failure occurs in the producing equipment.

This should be an automatic operation, accomplished by closing in the well preferably near the well-head. In the event of a pumping well, the prime mover must be stopped.
Production-Based Effective Vertical Permeability for a Horizontal Well
Authors: Yamada Tomimo , Hewett T. A.
Published: December 2007

The presence of a stochastic distribution of impermeable shale sheets strongly affects the production performance of a horizontal well. Oil recovery is drastically reduced, and its uncertainty is dramatically increased for a reservoir with high shale density and long correlation range. Construction of a probability distribution of the oil recovery based on many stochastic images requires extensive work and computation time. However, that probability distribution can be approximated easily if a single ranking parameter is assigned to each realization. Conventional effective vertical permeability, keV, which is based on vertical single-phase flow, was tested first because it governs horizontal-well productivity. This attempt was unsuccessful because of the inappropriate representation of inner and outer boundary conditions applied to the domain. Production-based effective vertical permeability, keV,p, which honors both inner and outer boundary conditions, was tried next. It successfully ranked each realization in terms of oil recovery after 10 years with excellent accuracy. The correlation between keV,p and recovery is independent of the shale density or correlation range. This study shows that honoring the appropriate boundary conditions to obtain a representative permeability is extremely important. The conventional permeability renormalization technique, in which either no-flow or constant-pressure boundaries are applied to coarse grids, fails for this reason.
Fluid Flow in Vertical Fractures From a Point Source
Authors: Clark P.E. , Zhu Qinsheng
Published: December 2007

Flow into a fracture from a point source recently has been the focus of attention in the petroleum industry. The suggestion has been made that, in this flow configuration, convection (gravity-driven flow) would dominate Stokes' -type settling for determining final proppant distribution. The theory is that when a dense fluid flows into a fracture filled with a less dense fluid from a point source, the density of the fluid will force it to the bottom of the fracture. This clearly happens when the two fluids have low viscosity. However, viscosity of both the fluid in the fracture and the displacing fluid and nonuniformities in the fracture influence displacement process significantly. Results presented in this study clearly show the effects of viscosity and fracture nonuniformity on the convective settling mechanism.

Introduction

While this paper deals with the convection mechanism for proppant transport in a vertical fracture, a review the history of proppant transport and placement is appropriate to help understand the experimental modeling of fracture flow better. Kern et al. reported the first model study. Their model was small, and their study dealt primarily with equilibrium velocities (the velocity where the height of the settled bed ceases to change). The authors used no crosslinked fluids and presented only limited data on thickened fluids. This paper laid the groundwork for the concepts of bank buildup and equilibrium velocity, concepts that dominated early thinking on proppant transport.

Babcock et al. made the next contribution to laboratory fracture-flow modeling. Their model was longer than that used by Kern et al., and they used several concentrations of guar and different sizes and types of proppant, fracture widths, and flow rates for their study. Their results were reported in terms of equilibrium bed heights, settling velocities, and equilibrium velocities. Schols and Visser reported data from a model that was ˜ 10 ft long and 1 ft high. Their work focused on equilibrium velocity and bank buildup and resulted in a set of equations that could be used to predict bed height and length.

Most of the early work with fracture models involved determining equilibrium velocities and equilibrium bed heights for "bankbuilding" fluids. Models constructed after 1975 were used to study particle settling. Clark et al. constructed a 12-ft-long by 4-ft-high model. This model was used to determine settling velocities in guar and hydroxypropyl guar (HPG) solutions. This paper includes what appears to be the first report of particle clustering during settling after shutdown. Sievert et al. report further data from the use of Clark et al.'s model. They observed that pack-growth rate as a function of proppant concentration in non-Newtonian fluids was nonlinear and that doubling of the viscosity of non-Newtonian fracturing fluids would result in a several-fold decrease in particle-settling velocity.
The Mechanical Stability of Propped Hydraulic Fractures: A Numerical Study
Authors: Asgian M.I. , Cundall P.A. , Brady B.H.G.
Published: December 2007

Proppant is sometimes produced along with hydrocarbons in hydraulically fractured petroleum wells. Sometimes 10% to 20% of the proppant is backproduced, which can lead to damaged equipment and downtime. Furthermore, proppant flowback can lead to a substantial loss of fracture conductivity. A numerical study was conducted to help understand what conditions are likely to lead to proppant flowback. In the simulations, the mechanical interaction of a large number (several thousand) individual proppant grains was modeled with a distinct-element-type code. The numerical simulations show that hydraulic fractures propped with cohesionless, unbonded proppant fail under closure stress at a critical ratio of mean grain diameter to fracture width. This is consistent with published laboratory studies. The simulations identify the mechanism (arch failure) that triggers the mechanical instability and also show that the primary way that drawdowns (less than ˜75 psi/ft) affect proppant flowback is to transport loose proppant grains in front of the stable arch to the wellbore. Drawdowns >75 psi/ft are sufficient to destabilize the arch and to cause progressive failure of the propped fractures.

Introduction

Proppant back production can significantly affect well economics because of (1) loss of fracture conductivity [unpropped sections of fractures tend to close under stress (Figs.1 and 2)], (2) the damage it inflicts on equipment (i.e., abrasion of pumps, casing, and wellhead), and (3) downtime and expense required to clean up the wellbore.

Refs. 1 through 3 address technical issues involved in the flowback of proppant. Ref. 1 presents experimental data that show how various properties and conditions (e.g., closure stress, fracture width, proppant embedment in the fracture walls, grain-size distribution, relative inclination of the fracture walls, and drawdown) affect the mechanical stability of cohesionless, unbonded proppant packs. It also raises fundamental questions regarding the process of proppant production (e.g., why does the transition from stability to instability occur over a narrow range of fracture widths and why do proppant packs in the laboratory fail at much smaller fracture widths than are known to exist in the field).

A numerical study presented in this paper addresses some of these fundamental questions. The objectives of the study are to help understand the mechanical process of proppant back production and to show how various field conditions and proppant properties affect the propensity for proppant flowback. This is accomplished by means of numerical simulations of proppant on a grain-size scale.
WELCOM: Evolution of Chemical Monitoring of Drilling Fluids and Industrial Perspectives
Authors: Aquilina Luc , Brach Michel
Published: December 2007

During the last ten years, the Bureau de Recherches Géologiques et Minières (BRGM) has carried out five experiments to monitor drilling fluids chemically. BRGM has developed a methodology adapted specifically to this type of work and has acquired considerable experience in interpreting the results. The results of these scientific investigations could have industrial applications. The purpose of this paper is to describe the evolution of the techniques BRGM used and the principal results acquired.
Evolution of Wetting Alteration by Adsorption From Crude Oil
Authors: Liu Yu , Buckley J. S.
Published: December 2007

Crude oils are complex mixtures of organic molecules, some of which can adsorb onto high-energy surfaces, altering mineral surface wettability. In cores, the extent of wetting alteration varies with oil and brine compositions and saturations as well as with aging time and temperature. Previous studies on flat surfaces have demonstrated rapid interaction between oil components and solid surfaces that can vary with the composition of the intervening brine phase. This study is designed to investigate interactions that occur after initial oil/solid contact. Wettability alteration is assessed by measurement of contact angles between pure fluids after removal of bulk crude oil. The influences of aging time, temperature, and fluid compositions have been considered.

Adsorption appears to proceed in two stages. Initial exposure of wet surfaces to oil produces weakly water-wet conditions. Longer aging may produce oil-wet surfaces or, in some cases, a return to more water-wet conditions. This second stage of the adsorption process may continue for days or even weeks and is influenced by temperature and fluid compositions. Desorption of crude oil components can occur when a treated surface is re-exposed to brine.
Drilling Mud Control in the Southwest Louisiana Coastal Area
Authors: Claus C.R. , Standish G.A.
Published: December 2007

Since March 1945, the Magnolia Petroleum Co. has drilled 39 wells in Southwest Coastal Louisiana. All wells were drilled within a comparatively small radius, but the area provides a large variety of problems. The deepest well drilled was 13,518 ft, and the total depth averaged 10,977 ft. Throughout this period drilling mud control and types of mud handled were:phosphate,red lime (late conversion),red lime starch (early conversion),red lime starch oil emulsion,precision controlled low alkalinity-low lime content, andgel muds for completion purposes.

Improvement has been obtained in effecting some or all of the following:more rapid penetration,reduction in drilling hazards,better evaluation of cores and logs, andbetter completions.

The geological sequence of zones penetrated range from recent sediments at the grass roots through the Frio section. Anticipation of high-pressure zones and incompetent formations entails precision control of drilling mud weights, and the unconsolidated nature of the various zones requires constant attention to the filtrate, viscosity, and gel strength values. In the Chalkley field, particularly, this combination of problems exists, where the formation pressures and overburden weight density values are in very close proximity. Design of casing and drilling mud programs must be modified to fit each well.

Introduction

Field and research work on drilling fluids has made constant progress, enabling operators to prospect progressively deeper horizons. Numerous papers have been written on the theoretical aspects of drilling fluid development, but in the field engineers have found it difficult to evaluate the role of specific mud constitutents when dealing in terms of thousand barrel mud systems. For that reason field data is somewhat lagging in technical report writing. However, applications of new techniques in the field have usually paralleled, and in numerous instances preceded, research work.