bluuebunny/crossref_metadata_2025 huggingface dataset:
Sedimentation and Free Water of Cement Slurries: Mathematical Models and Practical Solutions
Authors: Stiles D. A. , Baret J. F.
Published: December 2007

Because the water/cement ratio is a prime determinant of slurry properties, one objective of any slurry design is to keep the annular column of suspension homogenous until the cement has set. Microscopically, there are two extreme situations possible for a cement slurry; either it is dispersed, i.e., the particles are separated by repulsive forces between negatively charged surfaces, or it is flocculated, i.e., the particles form an interconnected structure held by electrostatic bonds between unlike charges. When the slurry is fully dispersed, it becomes unstable and shows sedimentation, resulting in large vertical density gradients while no supernatant water may be present. Conversely, when it is flocculated, free water may form with the suspension below remaining homogenous. Practically, intermediate situations where only a fraction of the particles are flocculated are sought, leaving the slurry stable but not too viscous.

In this paper, the first part describes and provides mathematical models for the two basic phenomena which may create a density gradient in a cement slurry: (1) the subsidence of a network of flocculated particles; (2) the sedimentation of individually dispersed particles. The second part presents slurries with various physical properties which display actual density gradients, and correlates these gradients with the models. The final part describes a newly developed anti-settling additive, which facilitates the design of stable cement slurries, including field case histories.
Ultrafine Cement for Oilwell Cementing
Authors: Clarke W. J. , McNally A. C.
Published: December 2007

Ultrafine cements are particulate, cementitious grouting materials that were initially developed as a replacement for unacceptably toxic chemical grouts for Civil Engineering applications. Several basic types are available: ultrafine slag cement (M1), ultrafine Portland cement (M3) and ultrafine portland/slag (M5). The chemical compositions and physical properties of these materials are shown in Table 1 and 2 and in Figure 1. Their extremely fine grain size enable them to permeate medium sands and fine fractures in rock. These and other properties have led to ultrafine M5 cement slurries being adopted for use in oilwell cementing applications, especially for gas and water control. The results of a series of experiments on ultrafine M5 cement slurry have indicated that it remains in a fluid state at high temperatures for at least as long as slurries formulated with Class G portland cement, demonstrating its applicability for use in hot, deep wells.

Applications for M5 involve squeeze cementing the Wasson South Unit 7514 casing leak at 3222 feet. 30 sacks of M5 were successfully used to seal the casing leak as the ultrafine cement was drilled out and the casing tested to 1000 psi with no bleed-off. In another application, M5 ultrafine cement was used to squeeze repair a casing leak. The previously repaired leak had broken down and was taking lift gas and giving up sour water. M5 was used to seal the leak and restored top allowable, water-free oil production from the well.
Comparison of Cuttings Transport in Directional Drilling Using Low-Toxicity Invert Emulsion Mineral-Oil-Based and Water-Based Muds
Authors: Hareland Geir , Azar J. J. , Rampersad P. R.
Published: December 2007

The vast majority of previous work on cuttings transport concentrated on water-base mud systems. The use of low toxicity oil-base mud continues to rise due to increasing environmental concerns with the use and disposal of conventional diesel oil-base mud systems. This study utilizes a full scale test apparatus to compare the cuttings transport performance of low toxicity oil-base and water-base mud systems with similar rheological properties, using limestone drilled cuttings. Extensive comparisons are now being made of cuttings transport efficiency for different mud types and hole angles from a practical standpoint.

The results indicate that the water-base mud and the low toxicity inverted emulsion oil-base mud systems perform slightly different at all angles of inclination except at the critical range 40° to 50° where the oil-base muds have higher annular cuttings concentration due to severe cuttings bed down-sliding. Limestone cuttings transport using a water-base mud, as well as a low toxic oil-base mud, shows cuttings concentrations increase with increasing mud yield point. The effect of increased yield point and plastic viscosity increases cuttings bed buildup, bed down-sliding and gel film thickness, thus reducing transport performance. In most cases the increase in hole inclination angle results in reduced transport efficiency.

Torque requirements are significantly less for oil-base muds having the same annular cuttings concentration. For both muds the torque requirements increase with increasing yield point and plastic viscosity at higher hole inclinations.
Theory and Application of Polynomial Type Curves
Authors: Jelmert T. A.
Published: December 2007

A generalized methodology for flow period diagnostics and type curve matching is discussed. The method which is based on the concept of a polynomial derivative function, can be used under a variety of flow conditions.

A new methodology to highlight possible constant terms during radial or polynomial flow periods is proposed. The constant term reflects the damage skin factor and the degree of convergence to the well.
A Pseudopressure-Pseudotime Transformation for the Analysis of Gas Well Closed Chamber Tests
Authors: Xiao Jinjiang , Reynolds A. C.
Published: December 2007

This paper presents methods for the analysis of gas-well, closed-chamber tests. It is shown that, in most cases, pseudopressure and pseudotime can be used to correlate gas-well, closed-chamber test results with the analogous liquid, slug-test solutions. This allows data from gas-well, closed-chamber tests to be analyzed using slug-test analysis procedures that assume single-phase flow of a slightly compressible liquid of constant compressibility and viscosity within the reservoir. Multirate analysis techniques were found to be applicable to gas-well, closed-chamber tests in terms of pseudopressure and time, not pseudotime.
Applications of a Continuum Damage Mechanics Model to Hydraulic Fracturing
Authors: Valkó Peter , Economides M. J.
Published: December 2007

A fracture propagation model that is intended to describe the geometry of a hydraulic fracture is also supposed to replicate the pressure level and trends during execution. This is often not the case with "abnormally high fracturing pressures" recorded presently. The problem stems from the intrinsic nature of linear elastic fracture mechanics. A relatively new branch of fracture mechanics, Continuum Damage Mechanics (CDM), has been used by the authors to construct a fracture propagation model describing fracturing pressure behavior consistently. The CDM version of the Perkins-Kern/Nordgren model (CDM-PKN) contains a combined parameter responsible for fracture propagation retardation. The parameter is the CDM substitute for the fracture toughness. The new parameter can be identified from step-rate tests and/or treatment pressure diagnostics. Knowing this parameter the CDM-PKN model can be used to predict the net fracturing pressure, fracture length, width and fluid efficiency. In this work several applications of the model are presented. A laboratory experiment, step-rate tests and a minifrac test are evaluated in terms of the new model. A possible range is established for the combined parameter. The large impact of the combined parameter on fracture design is illustrated by a case study.
Consequences of Fracturing Fluid Lag in Three-Dimensional Hydraulic Fractures
Authors: Advani S. H. , Lee T. S. , Dean R. H. , Pak C. K. , Avasthi J. M.
Published: December 2007

Research investigations on three-dimensional (3-D) rectangular hydraulic fracture configurations with varying degrees of fluid lag are reported. The interpretations deduced from the computed stress intensity factors for a wide spectrum of fracture slenderness ratios and effective minimum in situ stresses are dramatically different from those derived from plane-strain crack simulations. In particular, this paper demonstrates that a 3-D fracture model coupled with fluid lag at the fracture tip can predict very large excess pressure measurements for hydraulic fracture processes. In addition, this paper demonstrates that 3-D predictions of fracture propagation based upon critical stress intensity factors are extremely sensitive to the pressure profile at the tip of a propagation fracture and that plane-strain models of fracture propagation will underestimate the fracture pressures required for propagation. This rationale for the excess pressure mechanism is in marked contrast to the crack tip process damage zone assumptions and attendant high rock fracture toughness value hypotheses advanced in the literature. Selected model result comparisons with experimental data are presented to provide additional validation of the proposed 3-D rectangular geometry and fluid lag-fracture fluid pressure sensitivity phenomenon.
A Lesson in Site Management and Cleanup: The Bishop Tank Farm Remediation
Authors: Chaconas J. D. J. , Hunter R. W. , Huismann S. S.
Published: December 2007

The decommissioning of the Bishop Tank Farm began as a simple equipment dismantling and removal. However, the presence of soil contamination led to a costly and lengthy site remediation. The successful cleanup of the lease provided valuable lessons in minimizing environmental contamination and managing remediation at oil and gas facilities.
Waterflood Management During Production Shut-In of the McArthur River Field, Cook Inlet, Alaska
Authors: Wolodkiewicz D. E. , Walker R. K. , Pospisil Gordon
Published: December 2007

A case history of the Hemlock Reservoir of the McArthur River Field in Cook Inlet, Alaska demonstrates continued water injection during an extended production shut-in resulted in higher oil rates once production was resumed. With volcanic eruptions of Mt. Redoubt, located 30 miles to the south, production was shut-in for over three months during 1990 due to interruption of oil shipping and storage operations. This paper describes the results of effective waterflood management and the benefits of data gathering through pressure mapping and static tracer surveys during the production shut-in.

Maintaining water injection during the 1990 shut-in raised the average reservoir pressure by 230 psig and resulted in higher oil rates upon the resumption of production. Previous extended production shut-ins during 1976 and 1985 were followed by oil rate declines of up to 25%.

Reservoir pressures were monitored during continued water injection while the production was shut-in to define areas of lower pressure and poor reservoir conformance. Pressure mapping and static tracer surveys significatly improved the Hemlock reservoir description. Based on this data, infill drilling and waterflood conformance projects are being designed to increase recovery through improved vertical and areal sweep efficiency.

The waterflood management decisions and reservoir analysis techniques discussed in this paper provide useful insights to increase oil rate and reserves in future waterflood applications.

This case history describes waterflood surveillance and analysis which may be implemented during extended production shut-ins to improve reservoir description and define recovery enhancement projects.
Prudhoe Bay Rig Workovers: Best Practices for Minimizing Productivity Impairment and Formation Damage
Authors: Dyke C. G. , Crockett D. A.
Published: December 2007

A field wide review of rig workovers was carried out for the Prudhoe Bay reservoir to enable a set of ‘best practices’ to be drawn up and implemented. Particular emphasis was placed on well killing, together with the minimisation of formation damage and loss in productivity index associated with rig workover operations. Clear conclusions emerge which have a significant impact on productivity as well as reducing total workover costs.

The results of this case history are of direct relevance to all workover operations, detailing how cost effective well killing can be performed with the minimal productivity loss.
Prudhoe Bay: Development History and Future Potential
Authors: Szabo D. J. , Meyers K. O.
Published: December 2007

Prudhoe Bay Field is the largest producing field in North America. Prudhoe Bay is currently expected to yield at least 25% more reserves than estimated at field start up. This paper briefly describes the history of the field and some of the key developments that have taken place which have contributed to improved recovery efficiency. These incremental developments have resulted from a process of continuous surveillance, interpretation of field performance, management of multiple reservoir mechanisms, efficient utilization of the gas resource, and exploitation of the existing field infrastructure.

There are four dominant recovery processes currently at work in Prudhoe Bay; Gas Cap Expansion/Gravity Drainage, Waterflood, Miscible Flood, and Gas Cycling. Continuous management of these processes and analysis of field performance leads to identification of attractive targets for further development. Major components of the current field development plan are described in this paper.

Prudhoe Bay is seen by many as a mature oil field on an inevitable and irreversible decline. The major Owners in Prudhoe Bay continue to pursue incremental developments to mitigate decline and supplement proved reserves. Unit technical studies are typically done in multi-company, multi-disciplinary work teams. The pooling of resources in this manner has enabled efficiency gains and has promoted the sharing of ideas and best practices. The current view of potential future development targets and some of the opportunities under consideration for development of these targets are discussed.
Electrical Load Shedding Program at the Salt Creek Field Unit
Authors: Collier F. B. , Hardgrave E. N. , Stanley R. J. , Hatfield L. K.
Published: December 2007

This paper discusses a recently implemented electrical load shedding program at the Salt Creek Field Unit (SCFU) in Kent County, Texas. The project involves the interruption of SCFU electrical load during the wholesale utility's monthly peak load. By interrupting SCFU load during the utility's monthly peak, the SCFU electrical demand charge is reduced by $7.16 or $6.03 per interrupted kilowatt, depending on the time of year.

A dual demand electrical rate schedule makes the load shedding concept possible. With this rate schedule, the demand charge is divided into two components. One demand charge is based on the highest SCFU electrical load during the billing period while the other is based on the SCFU load during the wholesale utility's monthly peak. The goal of the load shedding program is to interrupt SCFU electrical load at the time of the utility's peak load thereby reducing one component of the demand charge.

A critical element to the load shedding program is the ability to predict when the wholesale utility's monthly peak load will occur. The utility's system load is highly dependent on the temperature in the utility's main load center which is located in and around Stephenville, Texas. By closely monitoring the utility's load and temperature/weather data in Stephenville, the time of the utility's peak load can be forecasted. Historical load and temperature/weather information are also utilized in peak load forecasting.

Another key element is the selection of SCFU electrical load to be interrupted during the utility's monthly peak. Currently, high pressure injection pumps and artificial lift installations are interrupted for load shedding purposes. Since the interruption of artificial lift installations results in deferred production, wells must be carefully prioritized for interruption so that lost revenue is minimized. Also, limiting total interruption time and frequency during each billing period is very important in minimizing lost revenue and cycling of lift equipment. Net profit of load shedding each artificial lift installation is determined by subtracting potential lost revenue from potential electrical savings.

This paper addresses the electrical rate schedule design, wholesale utility load forecasting, load shedding methodology, and results of the program to date.
Comprehensive Description and Evaluation of Polymers as Drilling Fluids
Authors: Talabani Soran , Hatzignatiou D. G. , Chukwu G. A.
Published: December 2007

Unlike conventional oil field drilling fluids, polymers are non-toxic, degradable and cause no serious environmental problems. This paper provides information regarding the microstructural behavior of polymers and presents a detailed description of their physical and chemical properties. It also investigates the performance of polymers with respect to drilling and cementing problems such as hole enlargement, shale stabilization, drilling through difficult formations which may cause ion contamination, drilling at high temperatures and cement bond with the formation.

Through experimental and field studies, this work shows which polymers provide optimum carrying capacity, acceptable fluid loss to the formation, smaller filtration cake and thus, the polymers which can be used to obtain a successful liner or casing cementing with less chance of gas leakage.
Emerging Coiled-Tubing Applications at Prudhoe Bay, Alaska
Authors: Blount C. G. , Ward S. L. , Hightower C. M. , Walker E. J.
Published: December 2007

Coiled tubing (CT) has been used at Prudhoe Bay since the early 1980’s, saving hundreds of millions of dollars in well servicing costs for such operations as cement squeezing, well cleanouts, stimulation, inflatable packers and plug placements, fishing, and temporary artificial lift applications previously performed by drilling/workover rigs. The majority of these CT jobs are currently conducted with 1-3/4″ OD CT which has proven to have excellent strength, capacity, and durability for typical field operations. With the recent availability of 2.0″, 2-3/8″, 2-7/8″ and 3-1/2″ OD CT, additional drilling and production applications once thought improbable to impossible have been achieved.
Cement Slurry Qualification, Field Mixing, and Quality Assurance Procedures for Coiled-Tubing Squeeze Operations in Prudhoe Bay, Alaska
Authors: Vorkinn P. B. , Sanders G. S.
Published: December 2007

This paper is presenting an overview of a refined methodology to secure optimal control of slurry properties for coiled tubing squeeze cementing. The basis is accurate specifications of critical slurry properties, specialized test procedures and slurry mixing procedures.

Special emphasis is placed on properties of filter cake generated during a squeeze. It was verified that slurries with copolymer type fluid loss additives as well as latex based fluid loss control additives produced firm, predictable filter cakes, while retaining other critical properties.

Shear energy imparted to the cement slurry proved to influence several slurry properties. Laboratory and field data verified that filter cake height, fluid loss, slurry consistency and thickening time stabilized when a certain level of shear energy was reached. Reproducibility of test data between laboratory and the field was within acceptable limits.

Specialized methods for preparation of cement slurries, in the laboratory as well as in the field, are described along with the supporting theory.

Quality assurance procedures throughout the process are described in detail.
Using Reservoir Simulation To Evaluate Operating Strategies in the Long Beach Unit
Authors: Skinner R. J. , Ames L. C. , Henderson C. P.
Published: December 2007

In 1985 the City of Long Beach initiated a series of reservoir simulation studies within the Long Beach Unit (Unit). The Unit, located in the Wilmington Field, California, is estimated to have contained 3.1 billion barrels of original oil in place. Since the Unit was formed in 1965 approximately 700 million barrels of oil have been recovered. A rapid decline in oil production warranted the need for a detailed study. Of key concern was the known areas of the field that have not been swept efficiently by waterflooding. Evidence from water injection profiles and new well saturations indicated significant reserves were being left behind and that there was potential to improve recovery performance. Reservoir simulation was used as a tool to identify areas of prospective remaining reserves, and to determine an optimum operating strategy to recover those reserves. Because of the large volume of oil in place, only a small percentage increase in recovery would translate to millions of dollars in revenue.
Complexities of Using Neural Network in Well Test Analysis of Faulted Reservoirs
Authors: Juniardi I. R. , Ershaghi Iraj
Published: December 2007

Neural networks models bring a significant dimension to the capability of computer aided approaches for well test analysis. This study shows, however, that when dealing with complex reservoirs, these models need augmentation from an expert system containing two types of information; independent field data and tables containing frequency of occurence of non-related models. A Monte Carlo Simulation method is proposed to provide the augmented statistical informations required for the expert system.
A 3-Dimensional Approach to the Modelling of the Hoadley-Westerose Gas Reservoir/Surface Pipeline Network
Authors: Sorensen Frank , Little L. C.
Published: December 2007

This paper presents the preparation of a model of the Hoadley-Westerose gas reservoir and surface pipeline network using a single phase 3-Dimensional reservoir / single phase network simulator. The 3-D reservoir description was preferable to the alternative tank type approach based on the dual permeability nature of the reservoir and the desire to calculate lease line migration. In spite of the complex reservoir description, the 3-D history match was not difficult to obtain, and computing times were very acceptable. The resulting model was found to be a reasonable representation of the network, even with the approximations which were required to treat the network as a single phase system. A previous multiphase model of the network did not provide a better match of the system.
Inflow Performance and Production Forecasting of Horizontal Wells With Multiple Hydraulic Fractures in Low-Permeability Gas Reservoirs
Authors: Guo Genliang , Evans R. D.
Published: December 2007

The applications of horizontal well technology coupled with hydraulic fracturing in the development of low permeability gas reservoirs are investigated.

Analytical single phase and multiphase pseudo-steady state inflow performance equations for a horizontal wellbore intersecting multiple hydraulic fractures are presented. The effects of permeability anisotropy, wellbore location eccentricity, and fracture characteristics are considered. The phenomena of non-Darcy flow is also accounted for in the inflow equation associated with the flow of gas phase. These solutions provide a basis for the productivity evaluation and production forecasting of horizontal wells with multiple hydraulic fractures.

A new analytical method for predicting the future production performance of gas reservoirs is derived. The method is based on material balance analyses in which explicit pressure expressions as functions of cumulative production data and gas properties are derived for various types of gas reservoirs. Detailed production forecasting procedures are developed by using the derived pressure functions and appropriate inflow performance equations. The new production forecasting method has been further implemented on a computer. As a result, the future production performance of a gas reservoir can be easily predicted for any given scheme of horizontal drilling coupled with hydraulic fracturing, and combinations of reservoir rock and fluid properties.

With an economic evaluation, the new method may be used in the initial screening of horizontal drilling and hydraulic fracturing prospects in low permeability gas reservoirs. It may also be used in daily production operations and reservoir management. A hypothetical case study is presented which demonstrates the applicability of the new inflow performance equations and production forecasting method in the recovery optimization of a low permeability gas reservoir by combining horizontal drilling and hydraulic fracturing technology.
Numerical Solutions for Pressure Transient Analysis
Authors: Warren G. M.
Published: December 2007

New research into wellbore modeling and grid generation techniques, has made feasible pressure transient analysis (PTA) based on a numerically simulated solution. This paper first briefly reviews the development, including determination of the gridding and time step control algorithms, and then discusses some of the technical advantages offered by a numerical model as compared to standard analytic solutions. The focus of the paper is on several field case studies. The cases presented involve partial penetration and non-Darcy flow turbulence. Since general analytic solutions for these problems are not available, this paper presents new numerical solutions for these types of problems. For example, isolation of mechanical skin from partial penetration and turbulence effects, as demonstrated in this paper, is an ongoing and critical problem with respect to evaluating the need for reperforation and/or stimulation treatments.

Preliminary findings from ongoing multiple phase PTA research, including modeling production below the bubble point and gas-water coning will also be presented.

The results demonstrate that a simulation approach offers a revolutionary new and completely general solution to evaluating wellbore and reservoir problems that are either very difficult or not currently possible to solve analytically. Proper and practical evaluation of well tests with a numerical approach cam lead directly to bottom line profit making decisions.
Analysis of Kansas Hugoton Infill Drilling: Part III—1993 Update and Infill Well Case Histories
Authors: McCoy T. F. , Reese D. E. , Fetkovich M. J. , Needham R. B. , Freeman B. E.
Published: December 2007

The purpose of this paper is to update our original Kansas Hugoton infill drilling studies. This paper examines the performance of the first 1513 infill wells placed on production through September 1992 and presents a number of infill well case histories. Official deliverability tests, production histories and completion data are used to evaluate infill well performance. The case histories review the performance of the older infill wells which shows the greatest potential of finding additional gas-in-place (GIP). These results indicate the infill wells have not found any additional GIP.
Material Balance Modelling and Performance Prediction of a Composite Gas Reservoir
Authors: Arthur J. E. , Chhina H. S. , Temeng K. O.
Published: December 2007

Gas reservoirs producing under pressure support sometimes exhibit a nonlinear relationship between cumulative production and (P/Z). A corollary effect is that the apparent gas volume in place increases with time and exhibits a sensitivity to changes in withdrawal rate. The nonlinear behavior may be attributed to dual porosity effects or aquifer support, which are both accounted for in the model. Without an aquifer being present, the nonlinear behavior may be a result of adsorption, natural fractures or an extremely tight gas-bearing region adjacent to a main reservoir. Proper modelling of such a system is crucial in determining ultimate recovery, and in choosing an appropriate development scheme.

In this paper we present results of a material balance mode! developed to study a dolomite, dual porosity gas reservoir in Alberta. The study was done to explain the better than expected performance of the reservoir, and to forecast future reservoir performance. The material balance model consisted of a main ‘productive’ tank in pressure communication with a low permeability, gas bearing matrix. Gas influx from the outer low permeability matrix results from pressure drop in the reservoir, and provides pressure and material support. Tubing, compressor and pipeline effects were analytically modelled and coupled with the material balance and deliverability models.

A single coupled analytical equation has been developed to account for reservoir, wellbore and surface facilities (compression, surface line) simultaneously.

An excellent history match was obtained with the model by properly adjusting the sizes and properties of the reservoir and matrix. Long-term performance was predicted under various schemes and constraints, including the effects of additional wells and compression. The results show that gas influx from matrix and ultimate recovery are very sensitive to withdrawal rate, and late-time performance of the system is observed to be influx-dominated. The impact of these results on future operating decisions is shown to be significant and is discussed in detail in the paper.
Deep Coal Seams: An Overlooked Source for Long-Term Natural Gas Supplies
Authors: Kuuskraa V. A. , Wyman R. E.
Published: December 2007

Recently, considerable attention has been focused on the long term potential of natural gas. Studies have included resources that range from conventional gas in Stratigraphie traps to unconventional gas locked in hydrates. However, these studies have overlooked one large and potentially productive gas resource — the methane stored in deep coal seams.

Currently, the conventional wisdom is that coals below 5.0 feet will be extremely low in permeability and thus unproductive. This viewpoint stems from the early laboratory based tests of confining pressure (depth) versus permeability and from the initial field tests in the deeper portions of the Piceance Basin, U.S.A.

Recent basin studies show that the resource potential in deep coal basins is considerable, both in the U.S. and worldwide. For example, in the U.S. the bulk of the 84 Tcf of coalbed methane contained in the Piceance Basin is in deep coals, below 5.0 feet. Even larger amounts of gas exist in deep coal seams in Alberta, Canada and other deep coal basins of the world. Also, comparisons of laboratory based permeability tests on coal with field results indicate that the lab tests may be unduly pessimistic. While the evidence that deep coals can be economically productive is limited, some data is now available and discussed in this paper. For example:An experimental completion of a Cretaceous age coal seam at 10,0 feet in the Deep Basin of Alberta, showed that deep coals contain substantial methane, that gas can be produced from such depths, but that the well completions are very challenging.A recently drilled 6,000 foot deep well at Piny on Ridge (Northern Piceance Basin) had an initial gas flow of nearly a million cubic feet per day.

The purpose of this paper is to examine the resource and production potential of deep coal seams and thus add this resource to the list of long-term sources of natural gas.
Ultrasound Logging in Cased Boreholes Pipe Wear
Authors: Bettis F. E. , Crane L. R. , Schwanitz B. J. , Cook M. R.
Published: December 2007

USI* UltraSonic Imager logs are run to evaluate cement, measure casing thickness and present the results as cement acoustic impedance and metal loss percentage.

The USI tool makes a high-resolution casing inspection, which allows identification of casing wear caused by drilling operations. Field examples illustrate the extent of the problem. Factors related to casing wear include drillpipe hard banding, hole deviation and, of major importance, directional dogleg severity. In one of the field examples presented, the operator ran a casing cutter and recovered the logged 7 5/8-in. casing. After recovering the casing, USI log results were compared to surface ultrasonic inspection and to physical measurements.

In another field, after discovering the serious nature of the casing wear that occurred during the drilling of wells below the 9 5/8-in. surface casing point, a number of operational changes to drilling and casing procedures were recommended. These changes were tested in the wells included in the field study. After each change, the results were checked by running the USI tool on the well.
Not All Technology is Necessary for Cost-Effective Cementing
Authors: Terry A. J.
Published: December 2007

From late 1990 through 1991, 43 wells drilled in the Gulf of Thailand were in the Jakrawan/Funan/Gomin fields (JFG). This was a higher pressure environment than had been seen previously, a situation which dramatically increased the frequency of remedial cementing. This paper will outline the resultant changes Unocal made to its cement program.

With multiple thin bed sands through open hole sections of 5000-7000’, 3-dimensional deviations, angles up to 60 degrees, close pore and fracture pressures, torque and drag limits, and 380 °F. static temperatures, effective primary cementing in the Gulf of Thailand is a challenge.

Operators often fail to recognize the importance of slurry placement mechanics such as centralization, circulation, pump rates and casing design. It has been proven that cement placement and mud removal are just as important as slurry property design1. However, it must be recognized that not all solutions are economically feasible and a certain amount of remedial cementing may be acceptable to the operator.

This paper outlines the unique problems faced in performing cementing operations in the Gulf of

Thailand and details the improvements made. This paper describes not only the application and success of cementing technology and concepts, but also rejects certain technology as uneconomical for the operator. Technology not applied due to limiting factors or cost is also discussed.
Deep High Volume Rod Pumping
Authors: Nolen K.B.
Published: December 2007

An investigation was made to determine optimum displacement needed to produce maximum fluid from approximately 8,500 ft. Both computed and actual field test data are given. Also, the load characteristics are compared between conventional crank-balanced, air-balanced and unconventional [Lufkin Mark II] pumping units. In addition, some data are pumping units. In addition, some data are presented on [1] sucker rod shock absorbers, presented on [1] sucker rod shock absorbers, [2] sucker rod electronic inspection, [3] sucker rod make-up and design changes, [4] USI Circle-A rod pump and [5] Delta II dynamometer use and results.

Introduction

Deep unprorated production in Montana, Wyoming and portions of North Dakota offers a challenge to high volume rod pumping. Generally, maximum volumes; of 350 BFPD can be effectively rod pumped from 8,500 ft. Most of these high volume wells are equipped with 5-1/2-in. casing, anchored 2-1/2-in. EUE tubing, 3-tapered rod string [1 in., 7/8 in. and 3/4 in.], 1-1/2-in. or 1-3/4-in. insert pumps and a bean unit with a 120-in. stroke and 456,000 in.-lb gearbox.

This paper presents the latest developments on sizing and selecting new equipment with some information given on limitations and improvements that can be made on existing equipment.

DETERMINATION OF OPTIMUM BEAM PUMPING UNIT SIZE

A study was made using a computer routine similar to the new API approach to determine optimum displacement needed to produce maximum fluid from approximately 8,500 ft. Since sucker rod strength is the limiting factor in high volume beam pumping, the beam unit geometry, stroke length, pumping speed and pump size were analyzed jointly to obtain optimum sucker rod performance. The maximum stress limits of high performance. The maximum stress limits of high strength API Class D rods are shown in Fig. 1. The API Class D rating is based on sucker rod steel having a minimum tensile strength of 115,000 psi or more. Most rod manufacturers rate their Class D rods at 125,000-psi minimum tensile strength or higher. For the purpose of this study, 125,000-Psi minimum yield rods were used without a service factor.

Computer runs were made with 1-1/2-in., 1-3/4-in, 2-in. and 2-1/4-in. bore pumps running at speeds varying from 7 to 13 strokes per minute. Six stroke lengths were analyzed: 100 in., 120 in., 144 in., 168 in., 192 in. and 216 in. A fresh water gradient of 0.433 psi/ft and a pump intake pressure of 100 psi was used.
Recovery of Attic Oil through Horizontal Drilling
Authors: Martins E. J. , Larez N. J. , Maraven S. A. , Lesso W. G.
Published: December 2007

The production of moderate-sized oil reservoirs, wedged up against major faults, frequently leaves residual hydrocarbons towards the top of the trapping mechanism involved. The beds are usually dipping at a high angle. Recovery of this attic oil in geologically complex reservoirs with conventional vertical or directional wells is, in general, not cost effective because of the reduced vertical column of oil in place and the ease of water coning. This situation exists in several Bloque I, Lake Maracaibo, Venezuela reservoirs that have produced oil over the past 40 years. A horizontal drainhole was planned, drilled and produced in one of these attic sections parallel to a large fault to recover a higher percentage of the remaining reserves. The location was identified using 3D seismic and confirmed with reservoir modeling and historical data. In addition, a pilot was drilled near the heel of the well to confirm the sand location. The first attempt to land a horizontal drainhole missed the sand due to the complexity of the geologic structure. A timely assessment of geologic and geometric data yielded a new model of the sand location, This, coupled with geo-steering techniques, allowed a second drainhole to successfully follow the sand in oil for more than 1100 ft. The well was completed with 7″ casing having a slotted section along the dra¡nhole. Initial tests showed 2400 BOPD. This was an eight-fold increase as compared to several vertical wells in the same reservoir.

The project was an overall success. Costs and time spent in drilling and completion were within expectations. This paper will show that coordination of the project through an integrated team consisting of the operator’s and the various contractor’s personnel was key in producing this result. Based on the first six month’s production performance, the well has paid for itself, and it will allow recovery of most of the remaining reserves in a cost effective manner. The experience gained on this well is serving as the basis for other horizontal projects in Lake Maracaibo and other parts of Venezuela.
Applications of a Systems Dynamics Weather Downtime Mobil for Drilling
Authors: Mamerow Steve , Brooker M. W. , Brett J. F.
Published: December 2007

In 1989, Amoco Production Company, as part of a worldwide continuous improvement effort by the drilling department, began tracking unscheduled events during drilling operations. It was readily apparent that downtime due to adverse weather conditions was contributing heavily to unscheduled events offshore, especially in the North Sea and Pacific Rim.1 When the weather downtime percentages were repeated in 1991, after the problem had been identified and publicized internally, drilling management determined that these weather problems were symptomatic of larger problems that encompassed much more than the drilling department and exploratory well schedule.

To study this problem a multi-disciplinary team consisting of two geologists, a geophysicist, a negotiator, three engineers, and a business process facilitator, was formed within the Worldwide Exploration Business Group. One of the team’s final products was a Weather Downtime Model. Using detailed weather data and site specific drilling information, the model can predict potential weather downtime problems (Appendix 1 contains a complete model description). Using hindcasts, in 1992, the team tested the model in a real-time situation(Danish sections Northsea). It also used the model to highlight potential problems as this concession was being developed. This paper describes the work of this multidesciplinary team and its actual use of the Weather Downtime Model.
Teamwork: The Economics Work
Authors: Sneider R. M.
Published: December 2007

Is an E & P company organized as synergistic teams more profitable and effective than one organized with a traditional heirarchy? One large oil company decided to find out the answer. They formed a small "synergistic" company to compete on exactly equal basis with one of their traditional E & P divisions. During five years of competition, the small company (35 employees) found about twice the reserves at about half the finding cost of the large division (175 employees).
New Frontiers in Like Kind Exchange for the Oil and Gas Industry
Authors: Brown T. A. , Brown D. A.
Published: December 2007

As an increasing number of companies divest of non-strategic property and acquire properties that contribute to their operating efficiency, tax-deferred exchanging is becoming a significant strategy. The roots of current tax law regarding Like-Kind Exchanges go back to the early 1920’s but have changed significantly as the tax law has been modified and case law developed in intervening years. Recent regulations have made exchanges much easier and less expensive to administer and broadened the scope of what qualifies as an exchange. Final Like-Kind Exchange tax regulations regarding deferred exchanges were issued in 1991 and 1992. In particular, the introduction of the Qualified Intermediary allows exchanging to be an ongoing corporate strategy rather than a highly customized opportunity. This paper will review the new regulations as they apply to the petroleum industry, give examples showing how effective use of the strategy will preserve much needed capital, and demonstrate how the use of an Intermediary expands the application and flexibility of tax-deferred exchange1 to a very broad spectrum of oil and gas entities. There is a significant benefit in developing a management procedure that regularly determines the applicability of tax-deferred exchange in all sales of assets and implements operational steps to execute an exchange routinely and in compliance with tax regulations.
Experimental Study of Environmental Remediation of Gulf Coast Crude-Oil-Contaminated Soil Using Low-Temperature Thermal Treatment
Authors: Chowdhury H. R. , Alcocer C. F.
Published: December 2007

Laboratory research was conducted to study the remediation of crude-oil-contaminated soil under the "Low Temperature" burner system. In this study, the effectiveness of remediation processes were investigated at three different levels of operating temperatures of 300°F, 650°F, and 2,000°F and three different levels of retention times 2, 15, and 30 minutes in the burner. Twenty-nine experimental tests were performed using four different types of oils. Before Weatherization, four different crude-oil-contaminated soils were measured. The results of Total Petroleum Hydrocarbon (TPH) levels for the samples were 45,000 mg/kg, 26,000 mg/kg, 27,000 mg/kg,and 29,000 mg/kg respectively. After Weathering the samples for two weeks, the results were 32,000 mg/kg, 19,000 mg/kg, 15,000 mg/kg, and 28,000 mg/kg respectively.

Then After Ashing by combustion, the experimental results of TPH levels for samples at 650°F and 30-minutes retention time were 980 mg/kg, 3,400 mg/kg, 2,800 mg/kg, and 2,900 mg/kg respectively. Based on the results of these tests, the study suggested that the cleanup of remediation of hydrocarbon/or non-hydrocarbon compounds by "Low-Temperature" burner system are possible but only at high retention time. The retention time required to achieve this remediation process range from 49, 52, 53, and 52 minutes respectively. For the "High-Temperature" burner system, the result of this study showed that at two-minutes retention time, the total remediation of oil-contaminated soil required the burner temperatures of 3,100°F, 2,900°F, 2,600°F, and 3,100°F for four different samples. From the experimental results obtained in this study the remediation of petroleum-contaminated soil under low temperature system is technically feasible.
A Conventional Reservoir Engineering Approach for Managing a Difficult Field
Authors: El Hamalawy F. A. , Elsayed G. A. , Swedan N. E. M. , Barden I. R.
Published: December 2007

Zeit Bay is a complex combination drive reservoir, consisting of sedimentary reservoir units partially overlying a tilted block of fractured basement reservoir. A secondary recovery scheme of gas reinjection into the original gas cap was applied after some four years of production.

This paper, briefly discusses the problems encountered in attempting to simulate field performance and describes the alternative measures and techniques implemented to improve reservoir management of the field and hence arrest production decline rate.

During the course of this study a number of areas of reservoir performance were evaluated. These included the movement of the gas and water contacts, gas and water displacement efficiency, reservoir pressure maintenance, the potential of oil recovery by gravity drainage and the field drainage efficiency expected from the current bottom hole locations.

Reserves improvements were established, based upon optimization of gas re-injection and a programme of in-fill drilling to improve field sweep efficiency.
Optimizing Upstream Processes Through Total Quality Management
Authors: Cevenini Mauro
Published: December 2007

This paper presents the models and steps that forge Deming Prize Winning Corporations- followed to successfully implement Total Quality Management (TQM) statistical systems in a multibillion dollar oil/gas operation: Texaco. These efforts were traceable to the high end double digits multimillion dollar saving, and cost avoidances to a lesser extent. TQM provided focus and involvement of all personnel (executive, supervisory, line) towards a common set of goals.
The Application of Total Quality Management in Linking Advanced Technology to Financial Performance
Authors: Ramlakhan Tensing , Chawathe Adwait
Published: December 2007

This paper presents an approach to improve the impact of advanced technology to the profitability of the petroleum company. This is a concern of management as petroleum companies continue to face difficulties in maintaining competitive advantage. Faced with severe regulatory restrictions, greater challenges in finding and extracting oil and gas, locally or in diverse international locations, companies need to be competitive in a volatile economic, technological and political environment. Advanced technology is a source of valuable data for managerial decision-making. The contribution of advanced technology should be measured by the extent to which it currently adds to or will improve the company’s competitive position. A Total Quality Management (TQM) approach is suggested as a way of achieving this advantage and improving the performance of the company through more effective management of technology. The benefit of applying TQM in this context is establishing a tighter coupling between advanced technology, human resources and the company’s profitability. This objective is achieved by proposing a Modified Management Model based on the ideas of Deming and Walton. An example of the modified model involving Imaging Technology has been presented for a hypothetical situation.