bluuebunny/crossref_metadata_2025 huggingface dataset:
Design Concepts for Offshore Produced-Water Treating and Disposal Systems
Authors: Arnold Kenneth E.
Published: December 2007

The general theories governing, produced-water treating equipment design are presented and qualitative conclusions drawn from the resultant equations. The design and use of various common components used in offshore produced-water treating systems are discussed.

Introduction

The engineer charged with designing an offshore produced-water treating and disposal system is faced with an almost insurmountable problem. While the endpoint is fixed for the design, usually little is known about the quality of the water that must be treated. The basic data set forming the basis of the current U.S. discharge guidelines is contained in a 1974 study conducted for the Offshore Operators Committee (OOC). Each type of final treating device was analyzed separately with specific conclusions drawn for pits, tanks, flotation systems, plate coalescers, fibrous media coalescers, and loose media coalescers. The report concluded: "Flotation units and loose media coalescers were found to produce the lowest mean effluent oil concentrations of the processes studied. Flotation is a widely used process and is applicable almost universally. Loose media coalescers were not selected to represent exemplary performance because of operating problems at many locations." The validity of this conclusion concerning loose media coalescers subsequently was verified by an in-depth study conducted by the OOC. The U.S. EPA analyzed these data, plus additional data furnished from industry and from EPA-conducted field verification studies, and arrived at their interim guidelines of 48 mg/L. The derivation of discharge quality based on exemplary performance of flotation systems does not imply that the installation of a flotation system will necessarily meet this criterion. In determining "exemplary" flotation systems the EPA eliminated many data. For example, in the original OOC study, about 25 % of the flotation systems analyzed had mean effluent-oil concentrations in excess of 48 mg/L. Thus, any water treating system that includes a flotation unit must be designed carefully for the conditions expected at that particular facility. Similarly, it is not necessary to install a flotation unit in each water treating system. The EPA-specified effluent limitations can be achieved with less sophisticated equipment under certain circumstances. W.L. Berry states:

" Not all treatment processes are applicable at all locations. Performance of water treatment systems is not only a function of retention time, design parameters, use of chemical coagulants…but is also influenced by a number of factors most of which the operator has little or no control over including: water characteristics, crude type and solubility, degree of entrained oil emulsification, sizes of the entrained oil droplets, and suspended solids concentrations and characteristics. [Because of these factors,] if identical treatment systems are installed at two different locations, the average produced-water effluent oil content may be quite different."

JPT

P. 276^
Limitations on Pressure Predictions for Water-Drive Reservoirs
Authors: Simons L.H. , Spain H.H.
Published: December 2007

Five water-drive fields, for which pressure predictions had been made within a few years after discovery, were re-studied when four to five years of additional pressure and production data became available. It was found that forecasts of the pressure in water-drive reservoirs may be subject to considerable uncertainty. Predictions can be erroneous when there is insufficient pressure history to define the characteristics of the aquifer, and when there are errors in the pressure, production or geologic data.

Introduction

The efficient operation of an oil or gas reservoir requires that the important characteristics of the reservoir be determined soon after its discovery. It is especially desirable to evaluate the pressure-production relationship quickly, for this relation-ship provides a basis for deducing the type of production mechanism that is operative, and for making pressure predictions. The pressure predictions, in turn, provide a basis for calculating efficient rates of production, determining whether water or gas should be injected, etc.

The importance of pressure prediction is such that forecasts should be made as accurate as possible, and the limits of error well defined. Historically, pressure forecasts for some fields have proved very accurate, while for others the forecasts were so erroneous that they resulted in the adoption of wrong, or at best, unnecessary production practices.

Pressure predictions made for water-drive fields are especially subject to error. Accurate forecasting for these fields requires that much be known not only about the reservoir proper but about the adjacent water-filled rock as well. The water-containing rock, or aquifer, may extend for many miles, and often there is only meager data regarding its thickness, permeability and porosity. Much of the information must be inferred from the previous pressure behavior of the reservoir. A brief pressure history may provide little information about the characteristics of the aquifer. Hence, pressure predictions made early in the life of water-drive fields can be incorrect.
Transition Time of Cement Slurries Between the Fluid and Set States
Authors: Sabins Fred L. , Tinsley John M. , Sutton David L.
Published: December 2007

Previous work on annular gas flow1–4 has shown that the behavior of cement between its fluid and set states is the controlling factor that may allow gas entry. This transition phase of cement previously has not been recognized in slurry design since its importance was not understood fully and since test procedures for its definition had not been presented or established.

To predict the occurrence of annular gas flow and to design cement slurries capable of helping to prevent annular gas flow, it is necessary to define the slurry characteristics at the beginning and end of this transition period as well as the length of time of the transition state, Test techniques have been developed to study the start of this transition period. Additional tests have been conducted to define the condition of cement required to prevent gas entry. The test techniques developed to define this transition period of a cement slurry are described.

Numerous job variables such as pumping time, placement time, slurry composition, and circulating temperature and pressure were investigated to evaluate their influence on transition time. A method for using transition time and static gel strength (SGS) development data to help predict annular gas flow and to evaluate annular gas flow control materials is discussed.
Fractured Reservoir Simulation
Authors: Thomas L. Kent , Dixon Thomas N. , Pierson Ray G.
Published: December 2007

This paper describes the development of a three-dimensional (3D), three-phase model for simulating the flow of water, oil, and gas in a naturally fractured reservoir. A dual porosity system is used to describe the fluids present in the fractures and matrix blocks. Primary flow in the reservoir occurs within the fractures with local exchange of fluids between the fracture system and matrix blocks. The matrix/fracture transfer function is based on an extension of the equation developed by Warren and Root and accounts for capillary pressure, gravity, and viscous forces.

Both the fracture flow equations and matrix/fracture flow are solved implicitly for pressure, water saturation, gas saturation, and saturation pressure.

We present example problems to demonstrate the utility of the model. These include a comparison of our results with previous results: comparisons of individual block matrix/fracture transfers obtained using a detailed 3D grid with results using the fracture model's matrix/fracture transfer function; and 3D field-scale simulations of two- and three-phase flow. The three-phase example illustrates the effect of free gas saturation on oil recovery by waterflooding.
Proppant Settling Correlations for Non-Newtonian Fluids Under Static and Dynamic Conditions
Authors: Shah Subhash N.
Published: December 2007

This paper presents a new approach for analysis of prop-pant settling data in non-Newtonian pseudoplastic fracturing fluids and develops drag coefficient correlations as a function of fluid model parameter n′. Results of experiments with these fluids under static as well as dynamic conditions are discussed. A wide range of n′ and particle Reynolds number is investigated.

It is shown that at low-particle Reynolds numbers the fluid model parameter n′ has a significant effect on prop-pant settling velocity. This effect diminishes at higher particle Reynolds numbers. The dynamic settling velocity data agree reasonably well with the correlations developed from static velocity data. Further, experimental results of earlier investigations agree well with the correlations of this study.
Digital Log Calculation of the Compensated Density Log
Authors: Head Mickey P. , Barnett Michael E.
Published: December 2007

Calibration and recording of the compensated density log with a digital logging system are discussed. The mathematical definition of the spine and ribs and the technique of computing compensated bulk density and amount of correction from tool count rates are explained.

Calibration Standards

The primary calibration standard for the compensated density log is freshwater-filled limestone blocks. The secondary calibration standards are blocks of aluminum and magnesium alloys of known composition. Since the compensated density log responds to the electron density index, Pe, a relationship exists that converts the electron density index to apparent bulk density, Pa.

Pa = 1.0704, ...................(1)

where

Pa= apparent bulk density as read by the tool, and Pe= electron density index.

By quantitative analysis of the two secondary blocks, the electron density index was computed and converted to apparent bulk density by Eq. 1. The values of apparent bulk density (more commonly known as bulk density) for the two blocks are 2.59 g/cm3 for aluminum and 1.71 g/cm3 for magnesium.

Spine Calibration

Calibration of the compensated density log with the Direct Digital Logging unit is performed by placing the tool in aluminum and magnesium blocks, accumulating the counts for 3 minutes in each block, and averaging the count rates. The count rates for the aluminum block (short-spaced and long-spaced counts/sec) define for each tool the response at a bulk density of 2.59 g/cm3, and the count rates in the magnesium block (short-spaced and long-spaced counts/sec) define a bulk density of 1.71 g/cm3. Fig. 1 shows the relationship of the magnesium block, the aluminum block, and the linear spine through the two calibration points. First, the four count rates are converted to logarithms where Las is the log of the short-spaced aluminum counts/sec, Lal is the log of the long-spaced aluminum counts/sec, Lms is the log of the short-spaced magnesium counts/sec, and Lml is the log of the long-spaced magnesium counts/sec. The slope of the spine is

Lml - Lal m spine = .....................(2) Lms - Las

The y intercept of the spine is

b spine = Lal - m spine (Las)................(3)

Since the values of bulk density and calibration count rates are known for both the magnesium and aluminum blocks, the ratio of difference in density to distance on the spine is

F spine = ..........(4)

F spine, m spine and b spine are stored on the digital program tape for a matched tool and source. These program tape for a matched tool and source. These calibration values are read from the program tape and are placed in memory when the log is to be run. placed in memory when the log is to be run. JPT

p. 167
Pressure Transient Behavior of Non-Newtonian/Newtonian Fluid Composite Reservoirs
Authors: Lund O. , Ikoku Chi U.
Published: December 2007

Pressure transient theory of flow of non-Newtonian power-law fluids in porous media is extended to non-Newtonian/Newtonian fluid composite reservoirs. This paper examines application of non-Newtonian and conventional (Newtonian) well test analysis techniques to injectivity and falloff tests in wells where different amounts of non-Newtonian fluids have been injected into the reservoir to displace the in-situ Newtonian fluid (oil and/or water).

Early time pressure data can be analyzed by non-Newtonian well test analysis methods. Conventional semilog methods may be used to analyze late time falloff data. The location of the non-Newtonian fluid front can be estimated from well tests using the radius of investigation equation for power-law fluids. An equation for calculating shear rates and apparent viscosities for power-law fluids in reservoirs is presented. An example problem is used to illustrate observations and solution techniques.
An Analytical Solution for Linear Waterflood Including the Effects of Capillary Pressure
Authors: Yortsos Y. C. , Fokas A. S.
Published: December 2007

In this paper we develop exact solutions for a model linear [one-dimensional (1D)] waterflood that includes the effects of capillary pressure. We show that at constant injection rates an exact solution is possible for a water/oil displacement process, for which the mobility ratio has the functional form (1)kroμwkrwμo=F(S−Sor1−Swr−S),

where S is the oil saturation and F is a parameter that can be taken as the water-to-oil viscosity ratio.

Explicit analytical expressions for the oil saturation distribution as a function of position and time are derived that account for the effects of capillary pressure. The solution is expressed in terms of F and a dimensionless parameter, β2, that denotes the relative magnitude of viscous to capillary terms. At high injection rates (β→∞), the solution reduces to the familiar Buckley-Leverett expressions, including the shock front solution when F> 1. From the analytical results one can calculate the capillary effects on the performance of the model waterflood.

This work, which for the first time presents an analytical solution for a linear waterflood that includes capillary effects, finds applications in two areas. First, it can be used to describe explicitly the performance of the model waterflood at low injection rates (small β), where the existing approximate solutions fail to account for the large capillary terms. Second, it can be used to check approximate analytical (such as the Buckley-Leverett), asymptotic, and numerical solutions.
A New Approach Toward Elimination of Slug in Shaped Charge Perforating
Authors: Delacour J. , Lebourg M.P. , Bell W.T.
Published: December 2007

Since the advent of the perforation flow laboratory, increased attention has been focused on new designs of shaped charges as applied to oilwell perforating. Data derived from the flow laboratory, in which charges are subjected to simulated down-hole tests, indicate that serious perforation plugging often exists due to the entrance of slugs into the perforated hole.

The slug or "carrot" is an intrinsic part of the jet process and its adverse effect is inherently characteristic of many commercial shaped charges which otherwise exhibit excellent performance properties.

Numerous approaches have been tried throughout the industry in an effort to prevent this flow-impeding slug from entering the perforated hole. Yet, publicly conducted tests indicate that none of these devices are entirely successful when applied under the clearance and pressure conditions for which the charges are designed. This paper deals with a new, direct approach toward the elimination of the slug or carrot in shaped charge perforating.

Herein is described a newly developed bimetallic liner for shaped charges, which when fired under pressure leaves no slug in the perforated hole and yet maintains the high performance of the conventional-type charge.

Introduction

During the past few years the testing of shaped charge tools, as applied to oilwell perforating, has evolved from simple surface shooting to tests conducted in a flow laboratory in which a study of the charge could be made under simulated down-hole conditions. In the flow laboratory, pressures and temperatures were elevated prior to firing the charge into a target of medium-hard sandstone material. An elaborate system was devised for firing the charge under various fluids and differential pressures. Provisions were made for actually "flowing" the perforated hole under controlled conditions. It was at this point that the term slug or carrot really emerged into oil-well perforating vernacular. While it had been noted that a slug of charge liner material often entered the perforation, these plugged test targets had drawn little attention. Now in the flow laboratory, it was found that this obstructing slug reduced the resultant flow through the perforation to as little as one-half that normally expected! It was then clear that the slug must be either eliminated from the shaped charge entirely or reduced to such proportions that it would be ineffective in plugging the perforated hole.
Problems of the International Petroleum Industry in 1957
Authors: Chapman A.H.
Published: December 2007

Introduction

American oil companies both large and small are commencing to devote more of their energies and their capital to production operations outside the United States. The recent granting of new concessions in Venezuela, North Africa, and Central America, have added many new names to the list of companies working abroad. In view of this healthy new development, it is appropriate at this time to review some of the problems which these companies will have to face in conducting their business successfully.

World Crude Demand

In 1956 free world production of oil averaged about 14,825,000 B/D, which represented an increase of 8 per cent over the average in 1955. This percentage increase would doubtless have been greater had it not been for the unfortunate closing of the Suez Canal and the necessity of rearranging shipping routes. Based on estimates of prosperity growth, many economists believe that for the next decade or so we can look at world increases in demand in the range of 8 to 10 per cent annually. We are, therefore, looking at a doubling of crude oil production over the next decade. The only thing which will interfere with this tremendous rate of growth will be war or some kind of nationalistic brake applied against the free use of energy throughout the world.

Against this estimate of increased demand we are witnessing the greatest world-wide exploratory effort that our industry has ever known. New techniques in geophysics, geology, and production are making this effort remarkably successful.

In spite of the plentiful crude oil supply position which exists today, both in the United States and abroad, these vigorous programs are likely to result in additions to world crude oil reserves. Many of these additions will be made by companies which heretofore have not been important producers outside of the United States and others who are in foreign work for the first time.
Reaction Kinetics of In-Situ Combustion: Part 2—Modeling
Authors: Fassihi Mohammad Reza , Brigham William E. , Ramey Henry J.
Published: December 2007

A model is proposed to analyze and differentiate between crude oil/oxygen reactions at different temperatures. The results of this analysis along with correlations of apparent hydrogen/carbon (H/C) ratio and molar carbon dioxide/carbon monoxide (CO2/CO) ratio indicated three major reactions at different temperatures. Low-temperature oxidation (LTO) appears to occur between the gas and liquid phases. Middle-temperature fuel deposition reactions appear to be homogeneous. The latter was found to be the rate-determining step in clean sands.

Natural cores from the reservoirs were found to have different kinetic behavior than the clean sand matrices for these reasons: (1) metallic additives lower the activation energy of the combustion reaction and hence shift the rate-determining steps, and (2) clay and finer sands adsorb more fuel.

The proposed kinetic model was found to be applicable to the five oils tested and hence may be generalized for application to any oil.
Pressure Decline Analysis for Prediction of Gas Reservoir Volumes
Authors: Hales H.B.
Published: December 2007

This paper describes a new method for combining pressure decline data and production rates to determine original gas volumes for gas reservoirs. The method is illustrated by application to actual field data. The new method is similar to the classical analysis which extrapolates a plot of p/z vs. cumulative production to the original gas in place. However, it allows for the influx of water into the original reservoir volume in a more rigorous manner than previous methods. It also provides an estimate of the reliability of the predicted original-gas-in-place values.

Introduction

Pressure decline analysis has become a basic reservoir engineering tool, particularly for gas reservoirs. It is readily apparent from the gas law of physical chemistry that the reservoir-pressure/gas-deviation factor ratio (p/z) should decline linearly with cumulative reservoir production, provided the reservoir is highly permeable and has a constant volume. Unfortunately, many reservoirs do not have a constant volume as a result of water influx that occurs with declining reservoir pressure. Most methods of accounting for this complication are based on the early work of van Everdingen and Hurst. Van Everdingen and Hurst used the Laplace transform to solve the partial differential equation governing single-phase radial flow in porous media and were able to relate production at an internal reservoir boundary to the pressure at that boundary. Many investigators have used this solution to account for water influx at the edge of a reservoir. These include the well-known techniques of van Everdingen et al., Hurst, Carter and Tracy, and Odeh and Havlena. The literature abounds in applications and variations of these methods.These methods can be visualized as modeling reservoirs as large tanks which gradually fill with water as the tank pressures decrease. Many workers have questioned the validity of such a model. In particular, Chierici et al. and McEwen have investigated the errors in the predicted hydrocarbon volumes that result from the unavoidable errors in the pressure measurements. Furthermore, Bruns et al. have shown that the effects of water influx on the nature of the pressure decline curve are diverse. Water influx can cause a concave upward pressure history, a concave downward pressure history, or an S-shaped curve. Pressure decline with strong water influx also can resemble closely the straight-line pressure decline of a depletion-type reservoir.This work is an attempt to overcome the short- comings of previous methods. The improvements are twofold. First, the model includes a moving water/hydrocarbon interface. In analogy with previous models, this allows a nonconstant tank volume. Second, the method provides not only a best estimate of the hydrocarbons in place but also an estimate of the accuracy of these results.

Theory

This work involves the development and use of a model that predicts reservoir pressure as a function of cumulative production and time. A schematic of the model is shown here.

JPT

P. 2261^
Optimization of Uranium Leach Mining
Authors: Schechter R. S. , Bommer Paul M.
Published: December 2007

In-situ leach mining for uranium is an emerging technology. Currently, the selection of a well pattern designed to recover mineral values is governed primarily by arguments based on hydrological considerations.

The effects of well pattern and well spacing on uranium recovery and oxidant utilization are considered in this paper. As expected, formation permeability heterogeneities and anisotropics are found to be important issues requiring careful consideration; however, it also is shown that chemical factors cannot be ignored. In particular, it is shown that the oxidant efficiency and the produced uranium solution concentrations are sensitive to the presence of other minerals competing with uranium for oxidant.

If the Damkohler number for competing minerals, which measures the speed of the reaction, exceeds that for uranium, the competing mineral will have to be oxidized completely to recover a large proportion of the uranium. If the Damkohler number is smaller, it may be possible to achieve considerable selectivity for uranium by adjusting the well spacing.

It also is shown that the oxidant efficiency is generally highest for well patterns that give streamlines of roughly equal length and that there is a minimum distance between injection and production wells to utilize oxidant most advantageously.
Chemistry, Physical Nature, and Rheology of Aqueous Stimulation Foams
Authors: Holcomb David L. , Callaway Ed , Curry Lynn L.
Published: December 2007

Laboratory equipment has been designed specifically to study effectively the microscopic structure of flowing foams at high pressures. In addition, application of foaming-agent optimization techniques to design stable foams at varying foam qualities is demonstrated at high pressures – i.e., 500 to 2,000 psig (3448 to 13 792 kPa). Capillary viscosity data for these foams is established and correlated with a video-photomicroscopic study of the flowing foam and their designated bubble qualities. Foaming-agent screening information from the tests is provided indicating the foaming-agent generic chemistry that allows optimal foam stability under high-pressure conditions.
Professional Engineering Liabilities Under U.S. Common Law and Securities Laws
Authors: Sheehan Thomas F.
Published: December 2007

The reporting requirements of oil companies to the Securities and Exchange Commission (SEC) in their 10-k filings on Reserve Recognition Accounting (RRA) provide petroleum engineers with both an opportunity and a problem. The opportunity is additional professional service income generated by the performance of reserve auditing and reserve estimating. The problem is generated by U.S. securities laws and their enforcement by the SEC on the accuracy of the petroleum engineer reports on reserve estimates and reserve audits. What the oil and gas industry accepts as accurate within the allowances of the industry will be rejected by the SEC.

Introduction

To put the liability of an engineer for his negligent acts, errors, or omissions in its proper perspective requires a review of the theory of U.S. tort and contract laws.In the U.S., for a plaintiff in a lawsuit to prevail in a tort action requires that he show there was a duty owed him by the defendant and that the defendant breached that duty by his negligent conduct (which was the actual cause of the plaintiff's injury), which is measurable in money damages for which the plaintiff prays for relief and judgment of the court. plaintiff prays for relief and judgment of the court. The defendant may respond to the plaintiff's charges that the plaintiff was guilty of contributory negligence or that the plaintiff's action should be barred by the statute of limitations.Engineers are subject to lawsuits not only from their clients but also from third parties who are not in privity with the engineer.The leading case abolishing the architect's protection of privity of contract was Inman v. protection of privity of contract was Inman v. Binghamton Housing Authority, decided in 1957.Courts have not recognized the distinction of the role of the architect as contrasted with that of the engineer in the design-construction process. While states license architects and engineers separately, each profession and the agencies regulating them tend to differ as to where one profession begins and the other ends.The best working definition I have found in explaining the difference between architecture and engineering is that the entire structure and all of its component parts is architecture, if such structure is to be used by human beings as a place to work or assemble. Therefore, if one wants to erect a courthouse, one would employ an architect, but if one proposes to construct a power plant, one should proposes to construct a power plant, one should employ an engineer.U.S. case law on the liabilities of engineers, thus, is wedded to that of architecture. Writers on the subject of their liabilities use the terms interchangeably, justifying their actions on the basis that architects usually have some engineering training and frequently perform engineering services.There is no body of case law for petroleum engineers because there have been so few cases where petroleum engineers have been sued. petroleum engineers have been sued. JPT

P. 1869
Bubble Point Pressure Correlation
Authors: Lasater J.A.
Published: December 2007

A correlation of the bubble point pressure for black oil systems is developed using the standard physical-chemical equations of solutions. The correlation is based on 158 experimentally measured bubble point pressures of 137 independent systems and is expressed in terms of the usually measured field parameters-flash separation gas-oil ratio, rank oil gravity, total gas gravity, and reservoir temperature.

The data were obtained on systems produced in Canada, Western and Mid-Continental United States, and South America. The average error (algebraic) in the representation is 3.8 per cent, and the maximum error encountered is 14.7 per cent.

Introduction

In the absence of experimentally measured properties of reservoir fluids, it is often necessary for the field engineer to make estimates regarding the fluid properties based on the usually measured producing parameters. To aid in these estimations, various correlations have appeared in the literature in recent years. Among the pertinent properties of interest is the bubble point pressure. A correlation for this parameter has been reported by Standing. However, this correlation was based essentially on California produced crudes and this limitation was pointed out with its presentation. The correlation presented in this paper utilized data on crude oil systems from Canada, Western and Mid-Continental United States, and South America.
Modeling the Number of Bids Received for Outer Continental Shelf Leases by Poisson-Type Models (includes associated papers 12296, 12297. 12338, 12369, 12570 and 12710 )
Authors: Bruckner Lawrence A. , Nachtsheim Christopher
Published: December 2007

Since 1954, the U.S. federal government has held hydrocarbon lease sales for areas on the Outer Continental Shelf (OCS). The U.S. DOE is charged with developing lease sale policies designed to increase competition on the offered tracts, Increased competition has been assumed synonymous with increased number of bids (NOB). To study the influence of alternative bidding systems on the number of bids received, a mixed Poisson-type model has previously been employed. Here we show why this model is not statistically supportable. A truncated model is proposed and is shown to be statistically justified for the number of solo bids over all sales and marginally supported for the number of joint bids on sales before the joint-bidding ban.

Introduction

Since 1954 the federal government has held hydrocarbon lease sales for areas in the OCS region of the U.S. In a typical sale, from 75 to 300 tracts were offered and 30 to 90% of these tracts received bids. The number of sealed bids received by tracts varied from 0 to 18 with approximately exponentially decaying frequency. The U.S. DOE is charged with developing bidding systems that will increase competition on the offered tracts. At present, if one sale generates a larger average number of bids per tract than another sale, the first sale is considered to have been more competitive.

Dougherty and Lohrenz rightly question the efficacy of judging different bidding alternatives "by comparing the average number of bids per lease" alone. Their paper attempts to address this inadequacy by developing a model for the number of bids received considering classes of differing" bidder interest." (A related model has been developed independently by Engelbrecht- Wiggans.)

Unfortunately, the Dougherty-Lohrenz model was not properly tested for goodness of fit. In the next section of this paper we statistically evaluate and reject the mixed Poisson model as proposed. Then, in the ensuing sections, a number of departures from the previous approach are considered. Solo and joint bidding patterns are examined separately. Then, certain ambiguities regarding the interpretation of the number of tracts that were offered but received no bids are discussed. The removal of such tracts from consideration led to the formation of a new, truncated Poisson-type model that provided some significant improvements in goodness of fit. Later we examine the effects on the distribution of NOB of the 1975 ban on joint bidding among major oil companies.

The Dougherty-Lohrenz Model

Dougherty and Lohrenz proposed a Poisson-type model of the following form to fit the number of bids (NOBS) on offered tracts.

Pk=F1 k+F2P(N=k/ 2)+F3P(N=k/ 3),

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

JPT

P. 1263^
The Effect of Temperature on the Flow Properties of Clay-Water Drilling Muds
Authors: Srini-Vasan S. , Gatlin Carl
Published: December 2007

Introduction

In the past few years the hydraulic aspects of rotary drilling have received considerable attention. It is generally recognized that accurate prediction of circulating pressures is desirable, particularly in those areas where a delicate pressure balance is necessary to prevent both blowouts and lost circulation. For calculation purposes the standard hydraulic equations for the pipeline flow of Newtonian fluids have been altered to facilitate similar calculations for non-Newtonian or plastic fluids. This latter classification includes most colloidal types of drilling muds.

Two properties: plastic viscosity, and Bingham yield value, are commonly used to define the flow characteristics of a plastic fluid. These are commonly obtained with multispeed viscosimeters such as the Fann V-G meter: Normally these measurements are obtained at some surface temperature, and are not corrected to circulating temperatures for calculation purposes. This may result in considerable error, particularly in the laminar flow calculations which commonly apply to the drill pipe-borehole annulus. The purpose of this study was to investigate the effect of temperature on the flow properties of some water-base muds.

Experimental Procedure

A laboratory model Fann V-G meter was used for measurement of viscosities, yield values and gel strengths. An aluminum water jacket with O-ring seals was machined to fit around the mud cup of the Fann meter.

All mud samples were prepared by thorough mixing in a Hobart mixer. Viscosity and gel strength measurements were made with the Fann meter using standard procedures. Flow properties of muds were studied at 80, 120, 160 and 180°F.

The compositions of the test samples are given in Table 1.

Results

Effect of Temperature on Flow Properties

The typical effect of temperature on the flow properties of these drilling muds is illustrated by Fig. 1. It was found that plastic viscosity and apparent viscosity decreased with an increase of temperature. However, the curves were not linear, and did not appear to follow any definite trends or patterns. Yield point data showed much more scattering.

Since a usable method for predicting drilling mud flow behavior with temperature was desired, an attempt was made to find a simple relationship between these variables.
CO2 Mobility Control
Authors: Dellinger Stan E. , Patton John T. , Holbrook Stan T.
Published: December 2007

As early as 1955, surfactants were recognized for their effectiveness in lowering gas mobility in reservoir cores by in-situ foam generation. For commercial field application a specific surfactant must have several important characteristics. It must be (1) highly effective with low cost, (2) chemically stable, soluble, and surface active in oilfield brines, and (3) unaffected by contact with crude oil or reservoir minerals.

A static foam generator, an adaptation of a conventional blender, was used to screen more than 150 candidate surfactants. Promising additives were then ranked in a unique dynamic test, developed at New Mexico State U., that involves sequential liquid/gas flow in a vertical tube packed with glass beads. Conventional flow tests in tight, unconsolidated sandpacks show good correlation with the dynamic and static screening tests, especially those data obtained in the dynamic experiment. Some synergism exists between additives with amine oxides and amides having the most beneficial effect on foam stability and gas mobility control.

The utility of cosurfactant stabilization was demonstrated in linear, two-phase flow tests through tight, unconsolidated sandpacks involving brine and gas. A solution containing 0.45% Alipal CD-128™ and 0.05% Monamid 150-AD™ can decrease gas mobility over 100-fold. The effect appears to be time-independent, indicative of good foam stability. Alipal CD-128 alone reduces gas mobility even more, usually by a factor of two. The moderating influence of a cosurfactant could be beneficial in avoiding "overcontrol" of mobility, especially in low-permeability reservoirs.
Rheology of Mobility-Control Foams
Authors: Patton J. T. , Holbrook S. T. , Hsu W.
Published: December 2007

Enhanced oil recovery (EOR) studies have consistently demonstrated the need to mitigate gas channeling in processes involving use of gas to displace crude oil. The use of foam for gas mobility control was first investigated in 1955, and an early field test by Union Oil Co. of California indicated significant merit in the concept. Work was undertaken at New Mexico State U. to provide rheological data of in-situ-generated foam in an attempt to define the mobility-lowering mechanism.

A capillary viscometer was constructed to measure the rheological properties of the most promising foams made with commercially available additives. Data collected at different shear rates show that foams are pseudoplastic in nature and several orders of magnitude more viscous, 10 to 100 cp (0.01 to 0.1 Pa·s) than their gas or liquid fractions. Significantly, foam viscosities are generally an inverse function of foam density, which is very advantageous in oil-displacement processes. In areas where gas fingering is pronounced, foam viscosity would be expected to increase with gas saturation and, thereby, would tend to mitigate further gas channeling.

The spontaneous generation of a viscous foam phase may also serve to reduce the flowing gas saturation and, thus, lower gas mobility because of the relative permeability effect. This technology is easily adapted to the water-alternating-gas (WAG) process involving CO2 or rich-gas displacement of oil.
Criteria for Structuring Surfactants To Maximize Solubilization of Oil and Water: Part 1—Commercial Nonionics
Authors: Graciaa Alain , Fortney Lester N. , Schechter Robert S. , Wade William H. , Yiv Seang
Published: December 2007

The phase behavior of nonionic surfactants having the same hydrophilic/lipophilic balance (HLB) but differing molecular weights has been studied. It is shown that the optimal alkane carbon number (ACN) depends on the HLB, but that increasing the hydrophobe molecular weight narrows the middle phase region, increases the solubilization parameter, and decreases the interfacial tension (IFT).

We found that the width of the three-phase region is in simple inverse proportion to the solubilization parameter at optimal salinity and that the multiple of IFT times the square of the solubilization is a constant. We also found it possible to synthesize nonionics that rival anionics in the properties mentioned above.
Effect of Mud Filtrate Invasion on Apparent Productivity in Drillstem Tests in Low-Permeability Gas Formations
Authors: Holditch S.A. , Lee W.J. , Lancaster D.E. , Davis T.B.
Published: December 2007

This paper shows that mud-filtrate invasion prior to drillstem testing in low-permeability gas formations can cause significant reduction of gas flow rate observed during the test. In addition, apparent gas permeabilities determined from test data can be much lower than the true values. These conclusions are supported by simulator results and field data.

Introduction

Interpretation of drillstem tests (DST's) in low-permeability gas formations is difficult. and this difficulty leads to uncertainty in identifying formations that, when stimulated, could become commercial completions. Operators have tong suspected that mud-filtrate invasion into these low-permeability formations could contribute to these uncertainties because of significant alterations in relative permeability and capillary pressure. These uncertainties led us to a study of the effects of mud-filtrate invasion on response in a DST; this paper reports the results of that study.

In this investigation, we used a two-phase, two-dimensional, fully implicit reservoir simulator to model DST's. The input data for the simulator were obtained from special core analyses. openhole tops, and DST's from the Falher sandstone in western Canada.

Model Description

The two-dimensional, two-phase model used in this study has been described previously in the literature. The model simulates the flow of gas and water in the formation using a simultaneous determination of saturations and pressures from finite-difference approximations of the gas and water flow equations. Capillary pressure and relative permeability data are input into the model; the model is therefore capable of simulating imbibition, water blocking, and cleanup effects. These effects are potentially important in DST performance.

To simulate a DST, uniform initial pressures and saturations were established in the model for all reservoir cells. To model the imbibition of filtrate into the formation prior to the DST, the pressure in the wellbore was set equal to (and maintained at) the hydrostatic mud pressure, and the water (filtrate) saturation was maintained at 100%. Water saturations and pressures around the wellbore increased during the imbibition period as filtrate moved into the reservoir. To model a mud filter cake, the permeabilities in the formation adjacent to the wellbore were reduced.

Following the imbibition period, a flow period was simulated. During the flow period, the pressure in the wellbore was maintained at a fixed pressure and the wellbore volume was set equal to the value of a typical drillpipe open to flow. Following the flow period, a pressure buildup test was simulated, with the wellbore volume set equal to a typical volume below the shut-in valve in a DST tool assembly .

JPT

P. 299^
Gravel Packing Controls Unconsolidated Sand in Venezuela Field
Authors: McReynolds Preston S.
Published: December 2007

Sand control has been the major problem encountered in producing oil from the unconsolidated Miocene sands in the Lagunillas area of Venezuela. One of the first completions developed to prevent excessive sand production was the combination oil string in which pre-perforated casing was employed. In most cases this method was unsuccessful in controlling sand and was replaced in 1951 by a special slotted liner completion. The slotted liner technique has been effective in controlling sand and in obtaining high volume producers in the Bachaquero sand member. However, as a satisfactory completion depends upon the ability to wash the well into production outside the liner, this technique will soon become obsolete because of the declining reservoir pressure in the Bachaquero field.

A program to evaluate gravel packing as a replacement for the slotted liner technique (see Fig. 1) and to provide a sand control method for use inside existing pre-perforated completions was initiated in April, 1956.

Forty-three wells have been gravel packed in the Lagunillas Dist. through Sept. 25, 1957, with two jobs considered as failures. Thirty of these wells are producing at an average rate of 520 B/D of 12 to 180 API gravity crude as compared to 268 BOPD for the average offset well. Eight wells are awaiting installation of production equipment and are expected to be satisfactory producers when opened to production.

Various problems concerning fluids, liner slot sizes and loss of gravel to the formation have been encountered. Solutions to these problems have been found and procedures for both open-hole and inside gravel packs have been developed that can be applied with confidence to the sand control problems that exist in the Bolivar coastal fields.

Introduction

A program to evaluate the applicability of gravel packing as a sand control method to wells in the Lagunillas Dist. was initiated in April, 1956.
Hydraulic Fracture Propagation in Layered Rock: Experimental Studies of Fracture Containment
Authors: Teufel Lawrence W. , Clark James A.
Published: December 2007

Fracture geometry is an important concern in the design of a massive hydraulic fracture for improved natural gas recovery from low-permeability reservoirs. Determination of the extent of vertical fracture growth and containment in layered rock, a priori, requires an improved understanding of the parameters that may control fracture growth across layer interfaces. We have conducted laboratory hydraulic fracture experiments and elastic finite element studies that show that at least two distinct geologic conditions can inhibit or contain the vertical growth of hydraulic fractures in layered rock: (1) a weak interfacial shear strength of the layers and (2) an increase in the minimum horizontal compressive stress in the bounding layer. The second condition is more important and more likely to occur at depth. Differences in elastic properties within a layered rock mass may be important—not as a containment barrier per se, but in the manner in which variations in elastic properties affect the vertical distribution of the minimum horizontal stress magnitude. These results suggest that improved fracture treatment designs and an assessment of the potential success of stimulations in low-permeability reservoirs can be made by determining the in-situ stress state in the producing interval and bounding formations before stimulation. If the bounding formations have a higher minimum horizontal stress, then one can optimize the fracture treatment and maximize the ratio of productive formation fracture area to volume of fluid pumped by limiting bottomhole pressures to that of the bounding formation.
Effect of Gas-Oil Ratio on the Behavior of Fractured Limestone Reservoirs
Authors: Jones-Parra Juan , Reytor Rafael Seijas
Published: December 2007

The porosities of fractured limestone reservoirs can be divided into two broad types in accordance with their effects on fluid distribution and fluid flow. In the coarse porosity, gravity segregation takes place freely and the resistance to fluid flow is very small. In the fine porosity there is no segregation and a high resistance to flow, and it has relative permeability characteristics similar to tight sandstones.

By analyzing the affect of the two porosities it is concluded that in some cases to recover the maximum amount of oil it is necessary to remove large quantities of gas from the reservoir by producing at high gas-oil ratios. In this manner the fine porosity is drained of its oil and the gas-oil contact drops slowly permitting higher production rates from the oil leg. Since this conclusion is contrary to widely accepted principles of conservation, a mathematical model (Fig. 1) was constructed to duplicate the conditions desired.

The behavior of the model indicates that under certain conditions it is possible to recover more oil by producing at high gas-oil ratios than by production at low gas-oil ratios, and that the rate of production is affected more by gas shut-offs than by the decrease in pressure (Figs. 2, 3, 4 and 5).

Introduction

It has been noted that certain limestone reservoirs behave in such a way as to indicate that there are two distinct types of porous spaces available for fluid storage and fluid flow. Regardless of the nature of these porous spaces the distinguishing characteristic is that in one type of porous space there is definite gravity segregation between the oil and the gas; while in the other, the gas evolved tends to remain distributed equally throughout the reservoir. For the sake of simplicity the porosity in which gravity segregation takes place at a fast enough rate to affect the behavior will be called "coarse porosity", while that in which this is not so will be termed "fine porosity".