bluuebunny/crossref_metadata_2025 huggingface dataset:
A Case History of the Pegasus Ellenburger Reservoir
Authors: Cargile Leslie L.
Published: December 2007

The performance of the 13,000-ft-deep Pegasus Ellenburger in West Texas has shown that, even in an extremely heterogeneous reservoir, gravity segregation drive can be an efficient producing mechanism.

Introduction

The Pegasus field is a large multizone field in Midland and Upton Counties, Tex. Oil productive intervals have been found in the San Andres, Spraberry, Pennsylvanian, Devonian, Fusselman and Ellenburger zones. The Pegasus Ellenburger is the deepest reservoir at an average depth of 13,000 ft and is also the most prolific oil producer. Since discovery in 1949, over 60 million STB of oil have been produced from this reservoir. The 4.5 million STB produced in 1967 was the highest annual oil production during the life of the reservoir. As production during the life of the reservoir. As of April, 1968, the reservoir pressure was more than 1,100 psi below the bubble point and the producing GOR had not significantly increased. producing GOR had not significantly increased. Development and Unitization

Magnolia Petroleum Co. (now Mobil Oil Corp.) drilled and completed TXL "A" Well No. 1 as the discovery well in the Pegasus Ellenburger field. This well, which is now the Pegasus Ellenburger Unit Well No. 15-1, was drilled in March, 1949, to a total depth of 13,295 ft, with a potential of 1,167 BOPD flowing with over 1,000 psig tubing pressure. From 1950 to mid-1954 the field was pressure. From 1950 to mid-1954 the field was developed at an average rate of 24 wells/year. In all, 119 wells have been drilled. The Pegasus Ellenburger unit became effective June 1, 1954. Fig. 1 shows the location of wells and the unit boundary.

Production and Injection History Production and Injection History Fig. 2 shows the oil and water production history, water and gas injection history, and GOR performance. The sharp decrease in oil production in 1951 resulted when the allowable was reduced from 395 to 200 B/D/well to allow time to initiate pressure maintenance operations before the bubble-point pressure was reached.

Pilot water injection was begun in 1955 and expanded in 1959 to a full-scale peripheral injection program. In 1960 the allowable was increased to 435 B/D/well (the 1947 yardstick value for 80-acre spacing). Water injection performance did not prove efficient and, in performance did not prove efficient and, in 1963, injection rates were curtained so that the effects of continued pressure decline could be observed. Gas injection was begun in 1967 and expanded to a full-scale crestal gas injection program in early 1968.

Geology

Structurally, the Pegasus Ellenburger reservoir is a three-domed anticline with a general northeast-south-west axial trend. (See Fig. 3.) The production area encloses almost 10,000 acres. There are major faults along the east and west sides of the field, and it is believed that numerous other faults (having smaller displacements) also exist throughout the field.

JPT

P. 1330
Scaled Model Studies of Thin Oil Columns Produced by Natural Water Drive
Authors: Khan A.R. , Caudle B.H.
Published: December 2007

The oil production performance of thin-oil-column type reservoirs producing entirely by natural water drive are discussed in this paper. The dimensionless production histories were obtained in a series of production histories were obtained in a series of scaled porous-medium laboratory-model tests under varying effects of rate of production, mobility ratio across moving boundary, ratio of oil- and water-sand thickness and mobility ratio across fixed boundary including the effects of different residual oil saturations in the water-invaded regions. This scaled-model study of thin oil columns indicated that greater recovery of oil results for lower values of the following: rate of production, mobility ratio across the moving boundary, water-sand thickness relative to the oil-sand thickness, and mobility ratio across the fixed boundary or residual oil saturation in the water-invaded region of oil sand The results of the study are given as dimensionless production history plots which may be used to production history plots which may be used to predict the performance of the field they represent.

Introduction

Oil fields producing under natural water drive can be classified into two major groups:

- an "edge-water drive" reservoir group in which the water is encroaching from the reservoir periphery, and

- the group of reservoirs in which the oil-sand is entirely underlain by an aquifer.

Reservoirs in the second group are further subclassified as "bottom-water drive" reservoirs and "thin-oil-column" reservoirs. The latter reservoirs are characterized by their relatively equal oil- and water-sand thicknesses and by having both the oil and water zone relatively thin.

When oil is produced from a water-drive reservoir by a partially penetrating well, water breaks through sooner or later before all of the displaceable oil is recovered. Many analyses of this general situation have been made with varying degrees of realism in their approaches, both theoretical and experimental in nature.

Pertaining to the scaled laboratory model studies of natural water drives using porous media, detailed investigations have been made by Henley, et al. on bottom-water drive and by Caudle on edge-water drive reservoirs. No laboratory model studies, however, have been mate to investigate the performance characteristics of thin-oil-column performance characteristics of thin-oil-column reservoirs.

This paper presents the results of a study on scaled model of thin-oil-column reservoirs, operated under varying conditions corresponding to the actual field practices.
The Chemical Logging of Drilling Fluids
Authors: Hughes T. L. , Jones T. G. J. , Geehan Thomas
Published: December 2007

A new method of measuring the concentration of ions in water-based mud filtrates is described. The method, based on ion chromatography (IC), provides a tool to monitor changes in the composition of both major ions (sodium, potassium, calcium, magnesium, chloride, sulfate, and carbonate) and environmentally sensitive ions (e.g., chromium and mercury) in mud filtrate during drilling. Changes in filtrate composition are caused by mud treatment and/or mud/rock interactions; chemical logs can be used to discriminate broad lithological changes. The mud-filtrate composition is modeled with a computer-based equilibrium model. The chemical-logging method has been applied to two case studies, one of which involved operation of equipment at the rigsite. The method can be used to monitor the composition of ions not currently analyzed by the widely accepted American Petroleum Inst. (API) Standard 13B-1 procedures.
Through-Tubing Sand-Control Techniques Reduce Completion Costs
Authors: Restarick H. I. , Fowler S. H. , Sedotal W. P.
Published: December 2007

Sand-control problems in existing wells typically result from improper completion techniques or changes in reservoir properties. While re-completion of many of these wells with conventional sand-control methods and workover rigs is economically unfeasible, enhance-ments to gravel-pack fluid systems, downhole equipment, and service capabilities have increased success and reduced costs in through-tubing recompletions, providing new options to the operator for successful sand control in existing wells.
Design of an Emergency Response Center
Authors: Phillips Malcolm
Published: December 2007

This paper describes the design of BP Exploration's Emergency Centre in Aberdeen. It reviews human factors considered to reduce stress, room functionality, communications, and information technology. It also describes the working emergency-response organization.

Introduction

BP first established a room dedicated to emergency response in 1976, following a fatal accident involving a helicopter in the Forties oil field. People dealing with the accident felt the direct impact of the media for People dealing with the accident felt the direct impact of the media for the first time. The main telephone switchboard rapidly became saturated with calls, making it extremely difficult to summon emergency support. Many key lessons were learned from that accident; the first was the need for a room dedicated to emergency response. So BP built and equipped a new room in its operation control center, which became known as the Emergency Control Room. An adjacent equipment room housed a telephone exchange that was independent of the company's telephone exchange, which facilitated group calls and direct communication with the company's offshore installations.

The accident also showed how important it is to record as much information as possible during an emergency.

Previous experience showed the need for a team with disparate skills during Previous experience showed the need for a team with disparate skills during emergencies. The wide variety of emergencies possible in the North Sea requires a multidiscipline team on permanent standby. The initial call broadcast to this team failed because of technical problems at a local paging company. A paging service under our direct control resolved the paging company. A paging service under our direct control resolved the problem. problem. The way that teams react during emergencies varies. Delayed actions or messages can cost lives. A system of checklists, known as "Prompt," can resolve this problem. Prompt provides a checklist for team activities; individual prompts also exist for each team member.

Prompt initially consisted of a sequence of 35-mm color slides controlled Prompt initially consisted of a sequence of 35-mm color slides controlled from a numeric key pad by the manager. A large central screen displayed actions that the team needed to complete during an emergency.

An emergency coordinator regularly updated slides after accidents and exercises to give feedback on any lessons learned. However, this process could take 3 weeks. A computerized Prompt allows system update within minutes.

The new Emergency Response Centre meets several requirements.A room dedicated to emergencies.Separate installation of equipment and facilities.A multidiscipline response team on permanent standby.A call-out service.Team communication facilities.Prepared checklists.Emergency records.Examination of team performance after an accident.An emergency coordinator.Up-to-date information.
Building Multidisciplinary Business Teams
Authors: Dyson C.J. , Winter N.C.
Published: December 2007

This paper describes an approach to managing E&P assets through the operation of multidisciplinary business teams (MBT's). This approach can result in improved asset performance in terms of efficiency, motivation, and business results compared with more traditional matrix-style hierarchies. This paper also outlines certain critical success factors for the long-term success of MBT's and discusses some of the risks of MBT operation.

Introduction

Optimal development of E&P assets is often encumbered by the organizational structure and internal workings of the company(s) owning the assets. All too frequently, the management hierarchies of E and P companies are ill-equipped to focus on the range and diversity of opportunities offered to them in their asset base. This occurs primarily because the authority to make decisions frequently is several levels removed from the source of technical knowledge and the individuals in the best position to make decisions. Thus, people in a position to recognize opportunities to build value into a set of assets often face both communication difficulties and internal competition in persuading senior management to take positive action. Compare this with a situation where all the professional input needed for the enhancement of a given set of assets is incorporated into one core team, and this core team is vested with total management responsibility. This is the essence of the MBT philosophy.

What Are MBT's?

MBT's are groups of staff brought together to manage a defined set of resources. The types of resources or "assets" that are best managed by an MBT are those that are capable of being run as a stand-alone business; that have a defineable value, in terms of both book value and/or market value; and that can be enhanced through value-adding activities. The key assets of an E and P company are licenses for exploration and/or operation. Most licenses fulfill all the above criteria of suitability for MBT management. It is helpful to think of types of E and P licenses as distinct asset types: production assets, production assets under development, and exploration assets. These asset types can be run on a stand-alone business basis and have a value that can be enhanced. The processes of adding value will differ for processes of adding value will differ for producing acreage compared with wildcat acreage. Nonetheless, all can, individually or jointly, constitute the basis of an independent business unit.
Group Unified Accident Reporting Database
Authors: Koene W. , Waterfall K. W.
Published: December 2007

Significant advances have been made recently in enhancing the standard of safety within Shell companies. Safety has been raised to a status equal to other primary business objectives. It is widely accepted that accident prevention is part of good business practice and that a safe operation normally is an efficient operation. Safety programs are being widely implemented that involve all employees, from top management to the contract staff, and the benefits are being realized.

The effectiveness of any safety program, however, must be monitored continuously. Injury and accident statistics play an important role as a prime indicator of safety performance. Statistics form part of the safety management process, indicating the success of the safety programs being implemented and highlighting areas of weakness.

Statistical information relating to the number and frequency of accidents, significant as it is, tells us little about how the accidents occur or about how to improve the intrinsic safety of the operations. More detailed information on accident causes and lessons derived from the investigation of noninjurious accidents and near-hits are required for this analysis and for the setting of appropriate remedial actions.
The U.K. Offshore Operators' Response to the Piper Alpha Disaster
Authors: Taylor B.G.S.
Published: December 2007

This paper describes the U.K. government's inquiry into the Piper Alpha disaster and examines one organization's response to recommendations from that inquiry.

Introduction

Immediately after the July 1988 Piper Alpha disaster, U.K. offshore operating companies reviewed their "software" procedures, such as permits to work, and initiated "hardware" changes based on lessons learned from the disaster. These included provision for and siting of emergency shutdown valves, subsea isolation systems, prevention of smoke ingress to accommodations, provision for better marking and screening of emergency walkways, and improved firefighting systems.

The government inquiry into Piper Alpha, headed by Lord Cullen, was given two tasks: to determine the cause of the disaster and to recommend how similar disasters could be prevented. The U.K. Offshore Operators Assn. Ltd. (UKOOA) contributed to the second task by providing the majority of expert witnesses.

Lord Cullen's report recommended sweeping changes to the U.K. regulatory regime and listed 106 specific recommendations for consideration by government and industry. UKOOA immediately endorsed the recommendations, is monitoring their implementation, and is coordinating the industry studies needed to support a number of them.

Background

UKOOA represents the 36 oil and gas companies designated operators of licenses on the U.K. continental shelf. Its main objectives are to provide an industry forum for discussion of matters of mutual interest to its members and, as appropriate, to provide the industry with a means of communication with the U.K. government and other relevant bodies. Its strength lies in the work of its committees. Volunteers from UKOOA's member companies comprise the 40 permanent committees and subcommittees.

The Piper Alpha disaster shocked the industry and the general public. In the aftermath of the personal tragedies came the inevitable self-examination and uncertainty. The designs and operating procedures, which for so long had been considered dependable and safe, now looked vulnerable. What had gone wrong? What could be done to prevent a similar accident?
Improved Simultaneous Determination of Formation Properties from Well Logs
Authors: Roper William A. , Jones Vaughn A.
Published: December 2007

A well log computation technique, similar to one developed earlier, can be used to differentiate the separate contributions of many possible minerals. The scheme may be extended to include the possible minerals. The scheme may be extended to include the effects of resistivity tools as they relate to porosity and saturation.

Introduction

The successful application of computer log analysis to the Chaveroo field by Burke, Curts, and Cox stimulated our interest in this method. The modification of their method, which is presented here, has been used successfully by Getty Oil Co. in the analysis of logs from several fields.

For both methods a set of simultaneous equations relating log response to formation composition is solved for the fractions of each component present. The method presented here allows inclusion of geological information and an arbitrary number of logs. As will be shown, the present method allows greater flexibility and control than the previous method of Burke et al.

To assist in visualizing, the mathematical relationships are supplemented by a graphical analogy. In the text of the paper, the solution process is discussed in terms of this graphical analogy. Computational aspects of the solution are described in the Appendix.

Basis of Computation

The basic assumption employed by Burke et al. was that logged values can be represented as a linear equation of the form:

where Xa is the logged or measured value of some property of a mixture containing n components. i property of a mixture containing n components. i is the fraction of component i in the mixture, and Xi is the property value assigned to a pure component i.

For example, if a formation is water-filled dolomite, the logged sonic transit time may be represented by

where

w + D = 1.

If the sonic transit times in water ( tw) and dolomite ( tD) are known, the fractions of water ( w) and dolomite (0D) can be calculated.

If the solid matrix is a mixture of dolomite and gypsum, and if sonic and neutron-porosity logs are available, the fractions of water, dolomite, and gypsum can be obtained by solving the following set of simultaneous equations:

Na = Nw w + ND 0D + NG 0G

ta = tw 0w + tD 0D + tG 0G

with the added restriction that all 0's must be positive. In these equations Na is the logged neutron positive. In these equations Na is the logged neutron porosity. porosity. The requirement of positive 's can be expressed conveniently in graphical form. In Fig. 1, pure component points are labeled W, D, and G, representing water, dolomite, and gypsum, respectively.

JPT

P. 827
Velocity-Porosity Logging in Volcanic Rocks
Authors: Carroll Roderick D.
Published: December 2007

Volcanic rocks exhibit a wide range in porosity and velocity and are an excellent medium for checking the time-average formula. An analysis of core porosity data and velocity logs from five wells at the Atomic Energy Commission's Nevada Test Site indicates that the time-average formula applies in these rocks. An equation with the constants tma = 54 sec/ft; tf = 189 sec/ft best fits the data. The close agreement of this equation with that generally assumed for sandstones suggests that in volcanic rock areas, where porosity-velocity data are lacking, existing interpretation charts for sandstones, relating sonic log travel time to porosity, may be applied to these rocks.

Introduction

The U. S. Geological Survey for several years has assisted the U. S. Atomic Energy Commission in evaluating rock media in the vicinity of underground nuclear detonations. The greater portion of this work has been concerned with volcanic rock sequences at the AEC's Nevada Test Site located in Nye County, Nev. In describing these media, physical properties play a large role, and a logical and necessary adjunct to these investigations has been the extensive use of wireline logs in exploratory wells. This paper concerns the use of velocity logs as a porosity-measuring tool in these volcanic rocks. porosity-measuring tool in these volcanic rocks. The use of velocity logs to determine porosity has generally been restricted to sandstones and carbonate rocks. This arises as a natural consequence of the favorable environment presented by these rocks for the accumulation of oil and gas. In the study of these rocks, Wyllie's time-average equation has been used widely.

Although volcanic rocks in general are not considered a favorable environment for petroleum, some instances have been reported of the location of oil in such rocks. Oil production has been reported from both a volcanic tuff and a welded tuff in the Eagle Springs field, Nye County, Nev., about 100 miles north of the Nevada Test Site.

Notwithstanding the poor suitability of volcanic rocks as a petroleum-producing medium, these rocks offer an excellent opportunity for testing the general applicability of Wyllie's equation because continuous sequences of saturated volcanic rock several thousand feet thick can be found in which porosity and velocity vary over broad ranges.
Influence of Pore Pressure on Drilling Response in Hard Shales
Authors: Gray-Stephens Douglas , Cook J. M. , Sheppard Michael C.
Published: December 2007

Results are presented from laboratory drilling studies of two different hard shales similar to those found in some areas of the North Sea. Two laboratory drilling machines with milled-tooth bits were used. Pore pressure was measured in all the experiments, and in some it was reduced to several megapascals below bottomhole pressure (BHP). Pore-pressure reduction was achieved by allowing the pore fluid to drain out of the shale while external stresses were maintained constant. The influence of BHP was studied for values from 3 to 33 MPa [435 to 4,786 psi]. The differential pressure, which equals BHP minus pore pressure, ranged from near balance to > 10 MPa [> 1,450 psi]. BHP was found to have a strong influence on drilling response, but differential pressure did not, contrary to conventional wisdom. The results are compared with other drilling experiments and single-cutter experiments in the literature.
Laboratory Study Provides Guidelines for Diverting Acid With Foam
Authors: Thompson K. E. , Gdanskl R. D.
Published: December 2007

A series of experiments was conducted in which foam quality, foam reactivity, diverting-stage volume, core permeability, and treatment design were varied. The goal was to determine how these parameters affect diversion in competing limestone cores. Situations involving natural permeability differences and diversion to damaged cores were considered. Experiments indicate that the minimum foam quality required for useful resistance to acid flow is 60%; foams of 70% or 80% quality were the most effective for diversion. Both acid and brine foams were used. Acid foams provide good diversion and can be included easily in a treatment, while in high-porosity, low-permeability limestones like chalk, brine foams appear to be more effective than acid foams. One can expect to maintain good diversion up to a permeability ratio of 10. Results also show that both types of foam effectively divert acid to damaged cores.
Density of Liquefied Natural Gas
Authors: Jensen Robert H. , Kurata Fred
Published: December 2007

An experimentally derived tabular correlation for LNG density as a function of temperature, pressure, and gas gravity has been designed for use in the field. The advantages of this correlation are that a gas gravity analysis is more easily obtained than a composition analysis and that density is determined by direct interpolation of the gas gravity tables.

Introduction

Liquefied natural gas, LNG, is being handled in increasing quantities, and a reliable and convenient method of determining LNG density is desired. If a composition analysis is available, the correlations of Harmens and of Lyckman, Eckert, and Prausnitz may be used to calculate LNG density.

Harmens' correlation was developed for the density of pure light hydrocarbon liquids at saturation and for the density of mixtures of such hydrocarbons, particularly of LNG. In the correlation, Eq. 1 is used particularly of LNG. In the correlation, Eq. 1 is used to calculate liquid density:

(1) p = C * F ( Tr )

C and F(Tr) were tabulated by Harmens. C is an empirical density constant, and F(Tr) is Harmens generalized density function. Tr is reduced temperature, T/Tc. To apply the correlation to mixtures, mixing rules were given to compute C and Tc from mixture composition and pure component values.

In the correlation of Lyckman, Eckert, and Prausnitz, reduced saturated volume Vr is given as a Prausnitz, reduced saturated volume Vr is given as a quadratic function of acentric factor:

(2) (1) 2 (2)Vr = V/Vc = Vr(0) + wVr + w Vr (3) p = M / V ,

where V is molar volume, Vc is critical molar volume, and M is molecular weight. The generalized functions of reduced temperature, Vr(0), Vr(1), and Vr(2), were tabulated by Lyckman, et al., in the range Tr = 0.560 to Tr = 0.990. Chueh and Prausnitz fitted the tabulated values to Eq. 4 and provided the coefficients a (j) to f(j).

(4) ( j ) ( j ) ( j ) ( j ) 2 ( j ) 3Vr = a + b Tr + c Tr + d Tr ( j ) ( j ) + e / Tr + f ln ( 1 − Tr )

Eq. 4 is valid for reduced temperatures from 0.560 to 0.995. Mixing rules were suggested by Chueh and Prausnitz to calculate pseudocritical volume and Prausnitz to calculate pseudocritical volume and temperature, and mixture acentric factor, for application of the correlation to mixtures of known composition.

In using the foregoing correlations, a composition analysis is required, and mixture pseudo constants must be calculated. To provide an easier and quicker procedure for the man in the field, a study was procedure for the man in the field, a study was undertaken to correlate LNG density as a function of three measurable properties: temperature, pressure, and the gas gravity of gasified LNG. A technician can make these measurements routinely with commercially available equipment.

Theory

To derive the LNG density correlation, equations are required for computing ternary mixture compositions, gas gravities, and liquid densities at fixed temperatures and pressures.

JPT

P. 683
Degradation of Titanium Drillpipe From Corrosion and Wear
Authors: Ferg T. E. , Craig B. D. , Aldrich C. S.
Published: December 2007

Drilling deeper than 35, 000 ft is limited by the extreme hook loads of steel drillpipe and temperature constraints of aluminum drillpipe. Titanium Alloys Ti-6A1-4V and Beta C have been proposed for use in drillpipe for wells deeper than 35, 000 ft because of their high strength/weight ratios, superior high-temperature corrosion resistance, and thermal stability. Their suitability in drilling environments, however, has not been evaluated. To determine the corrosion and wear characteristics of two types of titanium-alloy drillpipe under dogleg conditions, a test cell was constructed to test titanium drillpipe joints in contact with API Spec. 5CT Grade P-110 casing in different drilling muds. Titanium-alloy pipe and Grade P-110 casing wear rates were measured, and tests showed that both titanium-alloy pipes exhibited much greater wear than did steel drillpipe in water-based mud under the same conditions. Test data showed that the total wear rate of Alloys Ti-6A1-4V and Beta C in a drilling environment is a combination of mechanical wear and corrosion.
Effect of Multiple Hydraulic Fractures on Gas-Well Performance
Authors: Al-Hashim H.S. , Kissami Mimoune , Al-Yousef H.Y.
Published: December 2007

This paper describes the use of a single-phase 2D numerical model to study the performance of a well intersected by two perpendicular vertical fractures assumed to have either infinite or finite conductivities. Analysis of the simulated drawdown tests at a constant flow rate showed that the transient flow behavior of a well intersected by finite-conductivity (CfD<500) perpendicular fractures does not exhibit the bilinear and formation linear flow periods. However, when fracture conductivities were infinite (CfD =500), the formation linear flow period was observed. This period was used to determine the fracture half length and gave a fracture half-length equal to the sum of the two fracture half-lengths (xf + yf). The beginning of the pseudoradial flow period for any conductivity was found to decrease as yf/xf increased and to increase as the fracture conductivities increased for a given yf/xf. A single hydraulic fracture gave higher productivity than two fractures of the same total length when fracture conductivity was infinite. However, when fracture conductivity was low, the two fractures gave higher productivity than the single fracture.

Introduction

Hydraulic fracturing is an effective way to increase the productivity of wells producing from low-permeability formations. Considerable research has been conducted to determine the effect of hydraulic fractures on well performance and pressure-transient behavior. The results have been used to improve the design of hydraulic fractures.

The increasing use of hydraulic fracturing to improve the productivity of oil and gas wells in low-permeability reservoirs has resulted in many research efforts aimed at increasing fracturing capabilities and evaluating fracture characteristics in the postfracturing period.

The massive hydraulic fracturing (MHF) treatment is now a proven technique for developing commercial wells in low-permeability or tight gas formations. The purpose of MHF is to expose a large surface area of the low-permeability formation (in-situ permeability =0.1 md) to flow into the wellbore.

Over the past few decades, hydraulic fracturing and explosive shooting of wells have been used to improve the productivity of tight reservoirs. An alternative to these techniques, one that uses certain features of both but appears better for creating multiple fractures, is tailored-pulse loading.

Warpinski et al. in 1979 and Schmidt et al. in 1980 demonstrated that propellants can create multiple fractures in the field without damaging the wellbore region. Their results indicated that the long loading time of the pulse allows greater fracture extension and thus gives more opportunity for connecting a wellbore to the reservoir's natural fracture system.
Polymer Solution Flow in Porous Media
Authors: Harvey A. Herbert , Menzie D.E.
Published: December 2007

A method is described for the analysis of rate-dependent effects in the flow of polymer solutions through unconsolidated porous media. Experimental data are presented for solutions of polyacrylamide, polyethylene oxide, and polyacrylamide, polyethylene oxide, and polysaccharide.

Introduction

A major obstacle to wider use of polymer flooding seems to be the lack of a satisfactory method for predicting the performance of this oil recovery predicting the performance of this oil recovery process. Although it is frequently possible to process. Although it is frequently possible to predict that a polymer flood would recover more oil predict that a polymer flood would recover more oil from a reservoir than could be produced with a waterflood, it is difficult to make a realistic economic comparison of the two processes.

Waterflood prediction techniques which consider areal sweep and reservoir stratification have been used to evaluate the effect of improved mobility ratio on oil recovery. If accurate relative permeability data are available and if stratigraphic permeability data are available and if stratigraphic variations in the reservoir are known, then these prediction techniques may lead to a rough prediction techniques may lead to a rough approximation of the performance of a polymer flood. However, such prediction techniques fail to consider that the apparent flow resistance to a polymer solution depends on flow velocity as well polymer solution depends on flow velocity as well as permeability. These rate-dependent effects may be significant in a pattern flood, since fluid velocity is not constant. They may also be significant in a heterogeneous reservoir. Under favorable conditions some rate-dependent fluids will tend to even out the flood front in a stratified reservoir and thereby increase oil recovery. This effect cannot be anticipated with conventional waterflood prediction techniques.

The basis for much of the difficulty in predicting the performance of a polymer flood is a lack of understanding of the behavior of high molecular weight polymer solutions flowing through porous materials. Until we are able to predict how these solutions will flow through a simple system such as a glass bead pack, it seems unlikely that we will be able to develop a realistic mathematical model to describe the much more complex problem of flow in an oil reservoir.

It is the purpose of this study to develop a method for investigating the flow of these high molecular weight polymer solutions through unconsolidated porous media and to study the rheologic properties of solutions of certain polymers which, are of interest from the standpoint of possible application to polymer flooding.
A Systematic Approach for the Prevention and Treatment of Formation Damage Caused by Asphaltene Deposition
Authors: Leontaritis K. J. , Amaefule J. O. , Charles R. E.
Published: December 2007

Asphaltene plugging is a known cause of near-wellbore formation damage. Deposited asphaltenes can reduce effective hydrocarbon mobility by (1) blocking the pore throats; (2) adsorbing onto the rock, thereby altering the formation wettability from water-wet to oil-wet; and (3) increasing hydrocarbon viscosity by nucleating water-in-oil emulsions. Asphaltene flocculation and deposition can be avoided in some, but not all, cases. Some formation damage resulting from asphaltene plugging is permanent and hence must be prevented rather than treated. Prevention of asphaltene-induced formation damage should be started in the early stages of drilling and well completion, once the oil is known to be asphaltenic.

This paper presents a systematic approach to successful diagnosis, prevention, and mitigation of asphaltene problems during recovery of asphaltenic oils. A mechanism of asphaltene flocculation and deposition is proposed and analyzed, and the previously defined concept of asphaltene deposition envelope is further refined. Diagnostic technology is presented that can test the compatibility of drilling and completion fluids with any asphaltenic oil. Important issues that need to be considered in the design of treatments for asphaltene removal are discussed. Finally, the paper presents a methodology for restoring unfavorable wettability changes caused by asphaltene deposition.
Impairment by Suspended Solids Invasion: Testing and Prediction
Authors: Oort Eric van , van Velzen J. F. G. , Leerlooijer Klaas
Published: December 2007

A new model was developed to predict wellbore impairment by internal filter-cake formation during water injection. In the model, formation damage is approached semiempirically; no assumptions were made with respect to the specific mechanism underlying impairment. Model constants, derived from linear core-flow experiments, were used to calculate radial flow damage. Radial coreflow experiments subsequently were carried out to validate the proposed model. Theory and experiment were in good agreement. This paper shows that the model can obtain realistic performance and half-life estimates for water injectors. During the experiments, a pronounced velocity effect on impairment rate was found. The extent of impairment increased by several orders of magnitude when injection dropped below a critical inflow velocity of 2 cm/min. The generally accepted : "⅓: 17 rule" (the particle/pore ratio for internal cake formation) is confirmed for inflow velocities exceeding 10 cm/min. At low injection velocities (<2 cm/min), even smaller particles were found to cause increased damage: a "⅓: 114 rule" may be more applicable for such low inflow velocities.
Testing Thread Compounds for Rotary-Shouldered Connections
Authors: Bailey E. I. , Smith J. E.
Published: December 2007

This paper describes development of and the procedures and equipment described in API RP 7A1, Recommended Practice for Testing of Thread Compounds for Rotary Shouldered Connections, published in 1991.
Slant-Drilling Performance and Rig Design in Canada
Authors: Rushford J. D.
Published: December 2007

This paper describes the development of slant-drilling technology in Canada. Historical and future applications of slant technology are examined along with case studies demonstrating the advances that have been made in slant drilling. Improvements in rig technology are profiled along with proven field techniques that have contributed to the success of this technology.
Horizontal Slim-Hole Drilling With Coiled Tubing: An Operator's Experience
Authors: Ramos A.B. , Fahel R.A. , Chaffin Michael , Pulis K.H.
Published: December 2007

What is believed to be the first horizontal well drilled with directionally controlled coiled tubing recently was completed in the Austin Chalk formation. An existing well was sidetracked out of 4 ½ -in. casing with a conventional whip stock. An average build rate of 15°/ 100 ft was achieved in the curve, and a 1,458-ft vertical section was drilled with 2-in. coiled tubing, downhole mud motors, wireline steering tools, a mechanical downhole orienting tool, and 3 7/8-in. bits. This paper discusses the orienting and directional tools and techniques developed during this operation. It also describes improvements made for the second well.

Introduction

The Austin Chalk formation within the Pearsall field in Texas consists of a Cretaceous limestone through which production occurs from natural fractures. Drilling through these fractures requires careful preparation because the rig may encounter prolific flow of oil or complete lost circulation. During the discovery of the Pearsall field, wells were drilled vertically to the Austin Chalk. Horizontal drilling currently is the preferred technique for development of the Austin Chalk. Through horizontal drilling, a single wellbore can intersect several fractures, potentially increasing initial flow and ultimate oil recovery. Fresh water usually is used as a drilling fluid because it will control formation pressures when circulation is lost. Surface pressure containment equipment allows the flow of well fluids and gases to the surface under controlled circumstances where they are processed during drilling. In the field, this technique is commonly called "flow drilling." This method minimizes loss of drilling fluid to the formation and increases rate of penetration (ROP). The severity of either lost circulation or prolific flow can pose operational and safety problems. Loss of circulation can prevent adequate removal of drill cuttings, increasing the potential for sticking the drillstring. In addition, the logistics for providing an ample water supply in this semiarid area are complex because the large volumes required to power the downhole mud motors are lost to the natural fractures. Prolific flow from the fractures necessitates the handling of large volumes of oil and gas at pressures that can approach the limits of the surface equipment. Safely tripping into or out of the hole with drillpipe requires killing the well, which sometimes calls for the use of expensive and environmentally undesirable heavy brines. Therefore, a method of tripping while under pressure without killing the well would greatly enhance flow drilling operations. This problem was addressed by replacing the conventional drillstring with coiled tubing.
Theoretical Forces for Prescribed Motion of a Roller Bit
Authors: Biggs M.D. , Cheatham J.B.
Published: December 2007

This paper presents a systematic method for determining The forces on a simplified roller bit. The kinematics of an actual roller bit drilling in rock is complex; nevertheless, it is desirable to obtain an accurate analytical model. As a preliminary study, the roller bit is represented here by a preliminary study, the roller bit is represented here by a simple two-dimensional bit and the rock by a Coulomb plastic material. Results from previous work, plus plastic material. Results from previous work, plus additional assumptions, are incorporated into a computer program to determine the forces required to move the bit in a specified manner. Example problems are worked by use of this program. By problems are worked by use of this program. By studying similar but less complex drilling problems and by supporting laboratory work, one could eventually obtain an accurate analytical model for drilling an actual roller bit. This could lead to the compilation of a catalog of results that, in turn, would allow selection of the optimum drill bit for any given situation.

Introduction

The kinematics of an actual roller bit drilling in rock is complex so complex that it is not appropriate for basic analytical study. However, it is desirable to obtain eventually an accurate analytical model of rock drilling; with such a model the optimum drill bit for any given situation could be selected. As a first step toward obtaining a model, the actual roller bit is replaced by a simplified one and the rock is idealized as a more predictable material. Previous work, with appropriate modifications, has Previous work, with appropriate modifications, has been incorporated into this study. The previous work includes force-indentation studies of single teeth, and prediction of the path of fracture in both brittle and plastic stressed material. The work presented here is based primarily on a thesis.
Effect of Proppant Failure and Fines Migration on Conductivity of Propped Fractures
Authors: Gidley J. L. , Penny G. S. , McDaniel R. R.
Published: December 2007

Long-term conductivity testing at realistic environmental conditions has greatly improved the measurement of proppant pack permeability. However, the use of low flow rates to insure Darcy flow in such measurements has masked the total effect of failed proppant fines on proppant pack permeability. As flow rates increase, corresponding with those commonly found in the field, fines are mobilized and migrate into new positions that reduce the permeability of the proppant pack beyond that normally observed in conductivity measurements. This effect has generally been overlooked in proppant pack design.

This paper examines the extent of conductivity reduction caused by migrating proppant fines and the effect of proppant type on the extent of that reduction. The role of fines migration on the conductivity of proppant packs containing two different types of proppants, where the more capable proppant is used near the wellbore, is also evaluated.

Representative commercially available proppants, including sand, resin-coated sand, and low density ceramics are included in the study.
Shale Alteration by Water Adsorption
Authors: Chenevert Martin E.
Published: December 2007

An adsorptional isotherm technique makes it possible to define quantitatively the hydrational tendencies of any formation, thereby eliminating the cumbersome rock classification schemes presently used in industry.

Introduction

Properties of some argillaceous rocks are known to be Properties of some argillaceous rocks are known to be altered by adsorption of water. Montmorillonitic rocks, for example tend to expand and crumble when contacted by low-salinity water.' Quantitative data are available on the behavior and properties of montmorillonitic sandstones and pure clays, but not for rocks that can be broadly categorized as shales. (A shale can be described as being fine grained, argillaceous, highly compacted, and partially dehydrated.) The purpose of this work was to observe the behavior and measure the properties of a broad range of shale types-montmorillonitic, illitic and chloritic-when exposed to water. Investigators working with clays and montmorillonitic rocks have found that expansion is caused by water or ion adsorption onto the electrically charged surfaces of clays. Some investigators postulate that on a molecular scale an "ordering" of the water molecules takes place on the clay, resulting in the water's being "rigid" or "captured". The degree of capture (or the extent of total hydration) is best represented by an adsorption isotherm. When the clay is dry it consists of layers that are close together. Adsorption produces a net flow of water that causes the layers to separate, thus inducing internal expansive stresses. Hydration reduces the clay's strength and density, and alters its electrical resistance. Since shales are essentially quartzitic-feldspathic rocks that contain clay, it was felt that the mechanism just described would be responsible for most of the property alterations that take place when adsorption property alterations that take place when adsorption occurs.

Shales Studied

Samples of 50 shales from formations ranging in depth from 300 to 16,000 ft were collected and studied. All shales were restored to their original state of hydration, and samples of 12 shales were preserved at the wellsite and subsequently tested with minimal exposure to weathering. Control samples deliberately exposed to the atmosphere adsorbed water and eventually fragmented. All samples tested adsorbed fresh water (tap water was used) and evidenced physical alteration. It would be inconvenient to present data on all 50 shales. Instead, results of tests on six shales from as many different locations and depths are presented as being typical. Table 1 shows compositions from X-ray analyses of these shales (designated A through F) and gives their locations and depths. Table 1 also shows the weight percent water of each shale when it is in equilibrium with an atmosphere having a relative humidity of 50 percent. Generally, for shales containing an appreciable amount of clay, the weight percent water observed under these conditions percent water observed under these conditions exceeded 3 percent.
Field Test of Cosurfactant-Enhanced Alkaline Flooding
Authors: Falls A. H. , Thigpen D. R. , Nelson R. C. , Ciaston J. W. , Lawson J. B. , Good P. A. , Uber R. C. , Shahin G. T.
Published: December 2007

A test of cosurfactant-enhanced alkaline flooding, without polymer for mobility control, was conducted in a small reservoir in the White Castle field, Louisiana. Although the flood was unstable, the process recovered at least 38% of the waterflood residual oil in the reservoir as true tertiary oil and exhibited virtually 100% displacement efficiency. Alkali and cosurfactant propagated through the reservoir with acceptable and predictable losses.
p-x Behavior of a Rich-Gas Condensate in Admixture With CO2 and (N2 + CO2)
Authors: Chaback J. J. , Williams M. L.
Published: December 2007

Pressure/composition (p-x) behavior was studied by use of a rich-gas condensate with CO2 and nominally equimolar (N2+CO2) at two temperatures characteristic of gas-condensate reservoirs, 215 and 316°F. The revaporization of retrograde liquid also was studied at 215°F; CO2 was found to be more effective than (N2+CO2) in revaporizing retrograde liquid.