bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Approach to Borehole Stability Modeling for ERD and Deepwater Drilling
Authors: Tare U. A. , Mody F. K.
Published: December 2007

Borehole (in)stability in shales is a continuing problem which results in substantial annual expenditure for the petroleum industry ($700 million according to some conservative estimates). The environmental and business challenges of today have necessitated the development of a more realistic yet a more efficient modeling approach.

In order to develop an adequate borehole stability model, an in-depth understanding of the physics and chemistry of the interaction between the drilling fluid and the formation is extremely important. The chemical potential borehole stability model presented in this work addresses key issues in modeling borehole (in)stability problems for high angled extended reach and deepwater applications.

In addition to mud pressure penetration and osmotic interaction, the model also incorporates the effects of thermal stresses as a result of the drilling fluid and formation temperature difference. Several factors like the estimation of the in-situ shale activity, mud activity and rock strength properties based upon more conveniently tested laboratory parameters like porosity, shale dispersion, etc., are also included in this model.

The above model is the basis of a computer program which utilizes contemporary programming techniques and outputs information in terms of the mud weight as a function of hole angle and optimum salinity (for invert oil/synthetic based muds). Three case studies are presented in this work which demonstrate the straight-forward application and accurate predictability of the chemical potential borehole (in)stability model; to extended reach and deepwater drilling conditions.
Remedial Proppant Consolidation Using Resin Technology
Authors: Cole S. W. , Amundson M. W. , Allen J. S.
Published: December 2007

The Hugoton and Panoma gas fields are located in the Southwest corner of Kansas and the panhandles of Oklahoma and Texas. Historically, proppant production following propped hydraulic fracturing has been a recurring problem in these fields. For some wells, proppant clean out operations can make them unfeasible to operate. In all cases, the remedial costs associated with sand production are detrimental to the economics of the well.

In December 1996, a resin consolidation treatment was pumped on a Hugoton gas well to stop repeated pump failures due to post fracture proppant production. Based on the success of this treatment, the procedure has been used on 21 additional Hugoton and Panoma gas wells for six oil and gas operating companies. Of the 22 wells treated with resin, sand production has been eliminated on 14 of the wells. This paper reviews the candidate selection, design and execution of the resin treatments. Three case histories and conclusions from the overall results are also presented.
The Efficiency of Horizontal and Vertical Well Patterns in Waterflooding: A Numerical Study
Authors: Algharaib M. , Ertekin T.
Published: December 2007

The primary oil recovery mechanisms when are exhausted, leave enormous quantities of oil unrecovered. The advancement of oil recovery is a cardinal obligation in oil industry. From waterflooding to various thermal recovery operations, the predominant objective of the improved oil recovery processes is to increase the rate of recovery and the ultimate production from reservoirs. Most of the improved recovery processes are directed to improve the mobility of oil in porous media. Obviously, the field implementation scheme of these processes is also an important factor in determining the success of the project. The use of horizontal wells in waterflooding operations promises a pronounced improvement in the rate of oil recovery under certain conditions. In a low mobility ratio flood, horizontal wells are able to bring in an increase of 0.25 pore volumes to the recovery during the early injection periods compared to vertical wells. In this study, a numerical simulator is acquired to delve into the effectiveness of horizontal and vertical injector/producer well combinations in waterflooding applications. The effects of various waterflooding fluid parameters together with some operational design parameters are investigated. The analysis of the simulation studies conducted suggests that the combination, in which one horizontal and one vertical well are utilized, in several situations performs similar to the combination, in which two horizontal wells are incorporated.
Analysis of Horizontal-Well Responses: Contemporary vs. Conventional
Authors: Ozkan Erdal
Published: December 2007

Most of the conventional horizontal-well transient response models were developed during the 1980s. These models visualized horizontal wells as vertical wells rotated 90 degrees. In the beginning of the 1990s, it was realized that horizontal wells deserve genuine models and concepts. Wellbore conductivity, nonuniform skin effect, selective completion, and multiple laterals are a few of the new concepts. Although well-established analysis procedures are yet to be developed, some contemporary horizontal well models are now available. The contemporary models, however, are generally sophisticated. The basic objective of this paper is to answer two important questions: 1) When should we use the contemporary models instead of the conventional, simplified models? 2) How much error do we make by using the conventional models? This objective is accomplished by considering examples and comparing the results of the contemporary and conventional approaches.
Some Practical Examples Of Difficult Well Test Problems
Authors: Charles Dawari D.
Published: December 2007

Five practical examples of difficult field well test cases are examined. The source of the difficulty ranges from purely non-uniqueness problems in parameter estimation to several grades of severity of anomalous wellbore pressure and temperature behaviors. The examples include both gas and gas-lifted oil wells and demonstrate that regardless of the source(s) of the difficulty, they inevitably lead to a wrong or an extraneous solution. The examples show that non-uniqueness prone data lack clearly defined infinite acting radial flow segment on the log-log derivative profile, and that anomalous pressure responses inherently exhibits equally puzzling temperature profiles.
Optimizing Pumping Well Efficiency With Smart Fluid-Level Controller Technology
Authors: Giangiacomo Leo A. , Hill David R.
Published: December 2007

Oftentimes the management decisions that are required for pumping wells can be significantly improved by having an additional piece of information. If the fluid level in a producing well can be known in real time, many other pieces of information can then be calculated and/or inferred. With this additional information, better decisions can be made to improve the efficiency of the producing operation.

Fluid level machines, dynamometers, power analyzers, and pump-off controllers have all been very successful in increasing the operation of the rod-pumped well, and to a lesser degree, the progressive cavity and electric submersible wells. A recently patented fluid level controller technology enables the electrically pumped well to be optimized with real time fluid level data.

The fluid level controller can be used to measure and control the fluid level in a producing well without a packer to within a foot. It can penetrate foamy columns to read previously unavailable fluid levels below the foam. The level at which the pump turns on and off can be preset, and even automatically optimized. The producing bottom hole pressure can be calculated and used to improve the production and operating economics of many different types of artificial lift systems. It can also be used as a reservoir management tool. Its potential applications include:

preventing gas-locking, optimizing oil production from rate sensitive producers, conducting pressure transient tests, and evaluating the effects of injection well changes real time in an array of surrounding producing wells.

Field data has already revealed some interesting phenomena associated with downhole production observations that may lead to a better understanding of near-wellbore production mechanics. Changes in fluid level as gas rises through the annular column have been detected. Slug flow can be observed in what was thought to be steady state producers.
Problems Affecting the Design of Drilling Risers
Authors: Jones Marvin R.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

With increasing water depth many of the factors considered in making decisions related to the overall arrangement and operation of floating drilling equipment change significantly in magnitude and, consequently, in relative importance.

The paper considers ways of evaluating such factors with sufficient accuracy to enable one to make those decisions which must precede the actual design work. The evaluations also serve to define problem areas which will require attention in the design process.

It concludes that increased cost effectiveness is extremely desirable and designs with increased cost effectiveness require a greater amount of cooperation between equipment users and makers than has existed to date.

Introduction

Drilling risers guide tools into undersea wells and conduct the returning mud flow from the blowout preventer stack to the drilling preventer stack to the drilling vessel. They carry choke, kill, and control lines and provide the usual means for supporting the blowout preventer stack during installation preventer stack during installation and removal.

In performing these functions they resist static and dynamic loads which are hard to predict accurately. In turn, they impose loads on both drilling vessels and wells. The magnitude of such loads may actually determine the overall arrangements and procedures of drilling operations. All of the loads mentioned increase as water depth increases and we shall consider depths from one to six thousand feet.

Before one can effectively undertake the design of a riser, he must have a procedure for deciding exactly what arrangements and procedures will be most effective. procedures will be most effective. Having decided, one can assume load conditions and design components accordingly.
The Piper Field - Development Plan For Rapid Field Evaluation
Authors: Pinson A. E. , Daniel E.L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The discovery and six appraisal wells drilled in the Piper field provided data for the formulation of a flexible development plan which will permit rapid field evaluation. plan which will permit rapid field evaluation. The development plan will be modified as additional data are obtained so that the optimum development and operational plans can be used to obtain the maximum economic recovery from the field.

Introduction

The Piper field was discovered in December, 1972, and presented a classic example of the offshore oil industry's need to 1) make the decision to commit large sums of money toward development of a discovery at a very early stage of appraisal and 2) formulate development and operating plans rapidly in a situation of uncertainty regarding important natural features of the reservoir and its connected aquifer.

Preliminary studies on hypothetical fields of Piper size and water depth completed prior to the commencement of drilling permitted the Occidental group to begin an aggressive materials procurement and design programme immediately procurement and design programme immediately after the discovery well was drilled. Geological and engineering data obtained during the appraisal drilling provided information for rapid screening of possible oil displacement programmes and the selection of the general programmes and the selection of the general injection and producing well arrangement; a mathematical reservoir simulator was then used to devise a flexible development plan which will permit adjustments in well location and type (injection or production) as dictated by information gained early in the development/ producing phase. In particular, the development producing phase. In particular, the development plan should permit early determination of plan should permit early determination of the degree to which the field faults will act as impediments to fluid flow, and the strength of the natural water influx.

The development programme based on these studies includes a drilling/production platform which will accommodate a total of platform which will accommodate a total of 36 wells with plans for at least 24 producing wells and up to 10 water and 2 gas injection wells. Platform production and support facilities were designed for 250,000 B/D of oil production, 330,000 B/D of water injection, and 70 million SCF/D of gas injection. The platform will have two drilling rigs and will platform will have two drilling rigs and will incorporate safety features which will permit simultaneous drilling and production.
Drilling Through Deepwater Shallow Water Flow Zones at Ursa
Authors: Eaton L. F.
Published: December 2007

Wells drilled in the deepwater Gulf of Mexico often experience problems with shallow abnormal pressured sands. Successfully drilling through these sands has been an industry wide problem. Shallow water flow problems have caused the industry to junk wells prior to evaluation of any or all well objectives and prevented using discovery and appraisal wells as producers. Shallow water flow problems also caused the loss of the wells at the first Ursa Tension Leg Platform (TLP) site.

The Ursa field is located in the deepwater, 3800' water depth, Mississippi Canyon area of the Gulf of Mexico where shallow water flow problems have been severe. The sediments at Ursa contain massive, wet sands that are pressured above a normal seawater gradient at a very shallow depth below mudline. Different techniques have been used while drilling the discovery, appraisal, and development wells to attempt to successfully prevent and control shallow water flow problems. The severe shallow water flow problems at Ursa have been successfully overcome and the shallow batch set drilling program was completed at the second TLP site in mid-1998. Eleven wells, which required five casing strings, have been successfully drilled to below the base of the shallow water flow zones. This paper will discuss the problems encountered during exploratory, appraisal and development drilling at the Ursa field.
The New Concept Of Flexible Pipes. Their Manufacture. Their Applications In The Offshore Oil Industry. Field Experiences.
Authors: Behar Isaac , Levier Jean-Francois
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The scope of the intended paper is to show to drilling and production engineering specialists the various offshore oilfield applications of the new COFLEXIP flexible pipes. Latest field experiences: oil and gas flowlines between platform and subsea wells, jetting hoses for burying pipelines, kill and choke lines connections, pipelines, kill and choke lines connections, subsea power transmission and control by armored composite umbilical cables, will be described.

The description of the structural design and of the manufacturing process will be illustrated to enhance the specific qualities of those flexible pipes (diameters from 1" to 12" - working pipes (diameters from 1" to 12" - working pressures from 500 to 15,000 psi). pressures from 500 to 15,000 psi)

Introduction

Fifteen years of research and development, three years of industrial production, this is the background of production, this is the background of COFLEXIP flexible pipes.

The versatibility of their structural design allowing to adapt their performances to the required levels, added to the Company's marketing policy of cooperating with its clients for a system approach of the problems, have allowed to solve or improve a certain number of them in offshore oilfield activities.

We will review some of those achievements after a short description of the design of the flexible pipe and their manufacturing.

STRUCTURAL DESIGN OF THE COFLEXIP FLEXIBLE PIPES PIPES

Roughly it can be described as an articulated steel pipe plus armor and plastic layers. The last ones insuring plastic layers. The last ones insuring their tightness. Figure 1 shows an example of one of the basic structures designed by COFLEXIP.

We find from the inside to the outside:A Rilsan (polyamide 11 polymer) lining, special plastic that is inert to crude oil and most chemicals.
Casing Running Milestones for Extended-Reach Wells
Authors: Mason C. J. , Allen F. M. , Ramirez A. A. , Wolfson L. , Tapper R.
Published: December 2007

In the pursuit to access reserves at ever increasing departures the ability to successfully run very long casing strings in extended-reach wells is essential. Even though casing running has been fairly extensively studied, it is evident in high departure wells, that both theoretical understanding and modelling are beginning to lag behind operational experience.

In this paper we examine a number of case studies from British Petroleum's world-wide drilling operations and have focused on wells where long 9-5/8" casing strings have been run. Here, we define the length of 6,000m (20,000ft) as the casing running milestone.

We demonstrate the application of time-based data and advanced analysis techniques to illustrate a number of results that are fundamental to future progress. Examples include the effects of OBM and WBM systems, centralisation strategies and drag reduction techniques. In particular, we present the latest learning from full and partial casing flotation - which is now in routine use at the Wytch Farm oil field in Southern England.

The results in the paper also demonstrate an improved understanding of the effects of casing stiffness, wellbore tortuousity and mud rheology, in addition to the usual frictional drag mechanism.

In order to satisfy future requirements, it is desirable to develop metrics that can usefully quantify benefits whenever new techniques, technologies or strategies are used. To this end, we detail the shortfall in current drag modelling techniques and prescribe where improvements are required to fulfill immediate needs and shape future demands.
An Approach to the Evaluation of Oilfield Development Alternatives Using Reservoir Simulation Models
Authors: Archer John S. , Keith David R. , Letkeman John P.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The paper provides an approach to the use of reservoir simulation in North Sea oilfield development. The use of simulators prior to field production is a departure from traditional application and the authors have sought to illustrate that reservoir simulation models can be a relevant part of an overall field development strategy. The models are used to evaluate alternative production schemes and can be upgraded into operating tools as more field information becomes available.

Introduction

In this paper we will review the application of reservoir simulation models in assessing reservoir development alternatives for North Sea oilfields.

In recent years the vast exploration budgets allocated to the search for North Sea petroleum resources have resulted in the petroleum resources have resulted in the successful discovery of new offshore oil and gas fields. Many of these fields lie in water depths between 300 and 700 feet and are located in parts of the North Sea notorious for harsh weather. The focus of activity is now changing to some extent from exploration to development of these resources. Such development requires large capital expenditure and early return on investment. It is necessary to order development platforms and production equipment soon after initial field discovery, when only a limited amount of data is available from exploration wells. The huge investments required for field development justify the need for management to base plans on the fullest technical appraisals that are possible within the narrow time frame; appraisals that recognize the limitations of the available data and effects of different interpretations of the data.

To this end, reservoir simulation models are being used to optimize development soon after the field is discovered. Sophisticated computer methods are used for solving the mathematical equations that describe fluid flow in a grid system that represents the physical parameters of the reservoir. The equations are generally non-linear and require numerical solution with the aid of high speed computers.
Multipurpose Service Vessels: Conception, Design, and Well Intervention Operations
Authors: Galbrun Michel
Published: December 2007

Throughout the life of an offshore well, the operator can choose from a wide range of well intervention services to maintain adequate productivity. These services may be performed as planned preventive work, targeted campaigns or emergency well intervention requirements. In all cases, the repair or intervention work must be performed as efficiently as possible, so that production is recovered with minimum delay and intervention cost.

Until recently, such intervention work was carried out from existing vessels, such as drilling vessels, semisubmersibles, jackups, lift-boats, construction vessels or supply vessels. These units, diverted from their primary functions, are often less efficient and more costly than a fit-for-purpose unit. In addition, as the intervention service equipment is assembled temporarily on board these vessels, overall efficiency is reduced because of the nonproductive time needed to rig up, rig down and to interconnect the equipment, and to organize the resources needed to operate it.

This paper discusses the development of a new approach to well intervention that is achieved with a Multipurpose Service Vessel (MPSV). By analyzing most common intervention needs, reviewing safety issues, and evaluating operational factors and costs, the MPSV concept has been developed to provide operators with a cost-effective tool. The MPSV has specially adapted multifunction service equipment built in to ensure flexibility, reduce overall nonproductive time and optimize deployment of the services through improved logistics and reduced running costs.
The North Sea Supply Boat
Authors: Pruymboom A.A.W. , Strachan A.G.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the SPE-European Spring Meeting 1975 of the Society of Petroleum Engineers of AIME, held in London, England, April 14–15, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

This paper presents the development of the North Sea supply vessel as from the past, present and future. It gives a brief present and future. It gives a brief statement concerning an anchor handling procedure in the North Sea of a semi-submersible and a large North Sea type tug/anchorhandling/ supply vessel. Special attention is required for a better cooperation between the drilling companies and the supply boat company, in particular during the designing stage.

Introduction

The history of the North Sea supply boat cannot be described as being a very long one but at the same time it has seen the introduction of many unique innovations in marine technology.

The actual number of supply ships operating in the North Sea area today cannot be accurately assessed as ships are constantly being moved into the area from overseas and assigned to other operational areas. The arrival of new buildings on the scene can also confuse the figures as can the seasonal demands of the construction contractors. However I would estimate that approximately 250 supply boats of varying capability will find employment in the North Sea area during the Summer of 1975. Most offshore support craft activities are nowadays concentrated on the United Kingdom Continental Shelf where the majority of oil and gas discoveries have been made. My own Company has always favoured international involvement and in the 10 years of the Company's history, we have serviced drilling operations offshore Denmark, The Irish Republic, Holland, Norway, Sweden and the United Kingdom.

I propose to divide this paper into 3 sections, the past, the present and the future.

1. THE PAST

The first purpose-built supply boat for North Sea duty reared its head during the Spring of 1965.
A Novel Integrated Approach to Enhance Interpretation of PNC Log Data for Characterization of Layered Reservoirs
Authors: Ali Liaqat , Sultan Ahmad J. , Metwalli Magdi H. , Paulson Rodney D.
Published: December 2007

One of the fundamental limitations of Pulsed Neutron Capture (PNC) log interpretation is that the capture cross-section of water (Σw) is unknown in a reservoir where salinity of formation water differs from injected water. Currently, no method is available to adjust the capture sigma cross-section, which may correspond to the salinity of water mixture that is present in the vicinity of the logged well. This paper presents a novel integrated approach to enhance the interpretation results of PNC logs using produced water analysis data to calculate new Σw. The methodology developed assists in characterizing stratified carbonate reservoirs.

Results of this study show that water breakthrough layers observed in PNC log interpretations correlate with the specific gravity trends obtained from produced water analysis of nearby wells. The specific gravity trends show that the injected water is advancing in different layers indicating that little or no cross-flow exist among layers. We estimated salinity of water mixture at the time when the logs were run from the specific gravity trends and devised a new algorithm for PNC log interpretations.

Observations from this study suggest that if the salinity of the produced water at the particular time when the PNC log was run is used, the interpretation of PNC log data would be relatively more realistic. With field examples, we demonstrate in this paper that the new approach is more representative than the existing PNC interpretation techniques.
Recovery of Acidic Crude Oils With PEI
Authors: Friedman R.H.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the 45th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, held in Ventura, Calif., April 2–4, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Polyethylenimine (PEI) in dilute aqueous solution has been found to be an unusually effective recovery agent for acidic crude oils. It is more effective than the mineral bases against both high and low viscosity oils. No equivalent substitute was found nor was any agent found which acted synergistically with PEI. Application has been made for U.S. patent. patent

Introduction

Research on the use of bases to recover acidic crude oils has been conducted for many years. The first patent on the subject was in 1927. patent on the subject was in 1927. All the work cited in the literature deals with the use of mineral bases, sodium, potassium, or ammonium hydroxides, and with the exception of Jennings, et al, with crudes of relatively low viscosity. In the work reported here, viscosities are an order of magnitude higher than reported before and reservoir temperatures are 80 degrees F. At these higher viscosities, sodium hydroxide is ineffective. Dilute polyethylenimine (PEI) solutions with these more viscous acidic crudes reduce saturation to lower levels than previously achieved with sodium previously achieved with sodium hydroxide on low viscosity oils.

Though the precise mechanism by which bases aid recovery is moot, it seems evident that a surface active compound, a reaction product of the base and acid native to the oil, is responsible. When an alkali metal hydroxide is used to displace a very viscous acidic crude, the most frequent effect of this "soap" is the creation of a low viscosity oil-water emulsion, which immediately fingers through the oil ahead. As a result, little more oil is recovered with such a base than with water alone. This consideration led to a search for a satisfactory polybasic polymer. polymer. High viscosity was not the objective.
Recompletion of Wells to Improve Water-Oil Ratio
Authors: Rensvold Roger F. , Ayers Hugh J. , Carlisle W.C.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the 45th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, held in Ventura, Calif., April 2–4, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A treatment technique has been developed to improve the oil/water ratio in producing wells. An inexpensive, inorganic, low-viscosity fluid is injected into the water producing interval. This fluid sets to a stiff gel after a predetermined pump time. By placing a sufficient volume of fluid in the formation, a long lasting barrier to water production is achieved. The placement technique uses low pump rates and injection pressures, and includes a low-volume, low-pressure cement slurry tail-in.

Variations in placement technique have been developed to adapt the process to a variety of downhole problems. These include:Plug back for bottom water.Balanced pumping above and below a packer for treating the water producing interval packer for treating the water producing interval and simultaneously protecting the oil producing zone.Where a Tracker cannot be used, balanced pumping with a radioactive interface technique pumping with a radioactive interface technique for treating the water zone and, at the same time, protecting the oil zone.

Case histories are cited which show that the process can be successfully used in limestone, dolomite and sandstone formations. In many instances, an increase in oil production occurs when the production of water is eliminated or reduced.

In conclusion, various placement procedures allow the treatment technique to be used in almost any producing well. Furthermore, the establishment of an in-depth barrier in the formation against the migration of water is, in most cases, superior to conventional cement squeeze techniques.

Introduction

The production of water usually increases during the life of a well and can present many problems to the well owner. Some of these problems to the well owner. Some of these problems are: problems are:Increased lifting costs.Decreased oil production due to increased fluid level, downhole scale accumulations, and emulsions.Shortened life of surface and subsurface equipment due to corrosion and scale accumulation.
Development And Testing Of Jet Pump Pellet Impact Drill Bits
Authors: Eckel J.E. , Deily F.H. , Ledgerwood L.W.
Published: December 2007

A new method for drilling the earth's formations has undergone extensive laboratory and shallow earth drilling experimentation. This method, pellet impact drilling, uses the energy of a large mass of high-velocity steel spheres to break and crush the rock. Pellets are confined to a region close to the hole bottom. Motive fluid for transporting and recycling the pellets is supplied by a modified jet pump.

The pellet drilling method has inherent advantages over conventional rotary drilling. Firs only a nominal amount of weight need be applied to the hole bottom. Second, only a very small amount of torque is required for bit rotation. Third, means are available for continual replacement of the cutter medium.

The experimental laboratory work and analytical procedures necessary for the design of a pellet drill bit are described. In the laboratory program approximately half the effort was devoted to the development of a better understanding of the physical process, and half to the empirical testing of new bit configurations. Factors such as pellet size and velocity, jet pump characteristics and modifications, and power distribution are discussed.

The design and construction of a pellet impact bit for drilling a 9-in hole with 1 1/4-in steel pellets are described. Drilling performance in representative rocks, hydraulic operating characteristics, and metallurgical problems are discussed.

This paper discusses an attempt to reduce drilling costs through the development of a drilling method basically different from rotary drilling.

Publications on drilling research indicate that the major effort on the part or manufacturers and operators has been confined to research in rotary, or rotary-percussion drilling. This applied drilling research has produced significant gains in drilling rates and bit life, but thus far it has failed to achieve any major decrease in general drilling costs.
A Team Approach to Heat Management: Monarch 2F Steamflood, Midway-Sunset Field
Authors: Morrison Cheryl , Griston Suzanne , Smedley Gary
Published: December 2007

Chevron's Monarch 2F steamflood project currently consists of approximately 35 injectors and 90 producers. Heavy oil (14° API gravity) is produced from multiple sand beds averaging 55° dip. In late 1992 and early 1993, the original Webster E and D sand steamflood ceased. Subsequent vertical expansion steamfloods were installed in the Webster A through C sands, using slim hole injectors and commingled producers. Additionally, an areal expansion steamflood was installed in the Monarch and 10-10 sands.

In late 1997, a multidisciplinary team was formed to develop and implement a comprehensive heat management review of the steamflood expansion projects. The main objective was to optimize steam use and maximize oil production. The team's approach was to incorporate all available project data to assess heat and fluid migration in each target sand. Additional monitoring data were gathered to "fill-in-the-gaps" as needed.

This extensive data gathering and review process and revised operating strategy was implemented in stages over several months. The final outcome was a 40% reduction in steam use and a 25% increase in oil production. Fuel savings for 1998 exceeded $500,000 and steam related operating costs decreased by nearly $1/boeg. In addition, the team developed an infill drilling program to further realign steam injection and recover oil that would otherwise have been bypassed. Part of this realignment project was implemented in 1998, while the remainder of the work is scheduled for early 1999. The 2F property currently has an oil production rate of around 5,000 bopd and a steam-oil ratio of 1.2.
An Approach to the Problem of Slow Convergence for Automatic History Matching Procedures
Authors: Bishop Kenneth A. , Knapp Roy M.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The process of matching the performance history of a reservoir in performance history of a reservoir in order to determine parameter values for use in it numerical simulation may be described as an iterative effort to bring pressures and flows calculated by the simulator into close concert with those observed in the field. Development of automatic techniques which use concepts from optimization theory as strategy for parameter manipulation has been emphasized in recent years. Many of the studies which have appeared in the literature may be characterized by a preoccupation with algorithm development and relatively little concern for the nature of the performance measure chosen for performance measure chosen for optimization.

This paper focuses attention on the nature of a common performance measuring function. Certain characteristics of this function are analyzed in terms of their effect on the quality of a history match and on the performance of a common optimization algorithm. This analysis provides a basis for redefinition of provides a basis for redefinition of the independent variables of the function which modifies these characteristics an thereby improves algorithm performance.

The uncomplicated history match problem of determining porosity and problem of determining porosity and permeability values for the model of a permeability values for the model of a homogeneous reservoir which contains a single phase, slightly compressible fluid is used as a vehicle in the study.

Introduction

The development of reservoir engineering technology has been characterized by a steady increase in the sophistication of the mathematical and engineering techniques used.
Anomalous Potentials in Variable-Density Aquifers Affect Growth of Gas Storage Bubbles
Authors: Bond D.C.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

" Corrugated" flow in heterogeneous variable-density aquifers causes anomalous gradients in head or in potential. These gradients retard the establishment of equilibrium under and around a gas storage bubble after withdrawal of storage gas. The head under the storage bubble can be less than the head at the same elevation outside the bubble. Thus, gas can be forced into layers deeper than the injection strata.

Introduction

In a variable-density aquifer certain gravitational effects influence flow (Bond, 1973). The purpose of the present paper is to show:how these gravitational effects can be used to explain anomalies in indicated flow directions in reservoirs;how these gravitational effects reduce the response in pumping tests; andhow these effects pumping tests; andhow these effects influence the growth of a gas-storage bubble.

I have shown that in a variable-density aquifer, structure on the top and the bottom of the aquifer can influence the potential or the head in the aquifer. Also, relatively impermeable tilted barriers within the aquifer-barriers that divert flow from horizontal paths-can cause a difference in head. In an aquifer that contains such barriers, flow is diverted down and then up, over and over again, to give an undulatory, "corrugated" flow. That is, if water flows, it flows through a series of irregular U-shaped troughs (Bond, 1973).

In a region where a dense water is being displaced by a lighter water, the dense water in the U-shaped troughs is not necessarily displaced completely. The net result is a series of troughs, or U-tubes, containing light water on the inlet side and dense water on the outlet side of each of the U-tubes. Each U-tube produces a head difference, H 1.00 (in terms of fresh water), equal to (pD-pL) Delta Z, where pD and pL are the relative densities of the dense and light water, respectively, and Delta Z is the depth of the U-tube. In a series of U-tubes, the head differences are additive. Thus, anything within the aquifer that causes flow to deviate from the horizontal can introduce gravitational effects that result in differences in head.

One may argue that, even though barriers to horizontal flow are present, tortuous horizontal paths that permit some flow around these barriers can be found.
Potential Energy Sources
Authors: Jenny Wilbur M.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Introduction

The energy outlook for the United States for the next 10 years can be most grim when compared with the 50's and 60's. Prices and easy supply situation of these bygone years are only memories. We now face the realities of world interdependence for oil and gas supplies.

FEA Project Independence supply projections depend heavily upon selection of a range of policy options. All scenarios call for more policy options. All scenarios call for more coal and nuclear development. Vigorous energy conservation programs become a national imperative. Achieving the production levels that provide an acceptable degree of security will require massive infusions of capital, manpower and technology.

The broad strategic options outlined in Project Independence are: (1) increasing Project Independence are:increasing domestic supply,conserving and managing energy demand, andestablishing standby emergency programs.

The implementation of these strategies will have impact on:development of alternate energy sources,vulnerability to import disruptions,economic growth, inflation and unemployment,environmental effects, andregional and social impacts.

Whereas these points of impact are only illustrative of the energy concerns, a national energy policy will contain some elements from each point.

SUPPLY AND DEMAND BACKGROUND

Demand has been growing at a 4- to 5- percent rate in recent years. Since 1950, energy consumption in the U.S. has outstripped domestic production. Coal production recently has been at 1940 levels. Oil production has been dec g since 1970. The last year the U.S. added to gas reserves was 1967 (excluding the Prudhoe Bay addition in 1970).

Sixty percent of the world oil reserves and 70 percent of the oil moving in world trade is centered in the Middle East. All important oil exporting nations with the exception of Canada are members of the highly effective "trust" (OPEC).

Whereas the 1973 oil embargo had minimal effect on the U.S. economy at the time, it did set in motion a series of events that threaten U.S. well being as a nation. The first effects of the embargo were:cut off of 14 percent of U.S. oil supply,sharp oil price increase,reduction of $10 to $20 billion in (20, and500,000 unemployed as a direct result.
Evaluation of Highly Deviated Wells with Gamma Ray/Electric Logs and Cased Hole Density/Neutron Logs
Authors: Haley R.A. , Kirchoff D.L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

SARABAND computer analysis using the gamma-ray and induction logs in open hole with the compensated neutron log (CNL) and the formation density log (FDC) in cased hole provides an alternate method for evaluating provides an alternate method for evaluating highly deviated offshore wells in the Gulf of Mexico.

Introduction

The number of highly deviated holes being drilled in the Gulf of Mexico is increasing rapidly. Often the hole conditions can become so severe that unorthodox logging methods, consuming large amounts of expensive rig time, are required to complete a minimum logging program. The use of open-hole gamma program. The use of open-hole gamma ray-induction resistivity log (GR-ISF) and the compensated neutron-formation density logs (CNL-FDC) made in casing as input to a SARABAND analysis is proposed in this paper as an effective solution to some of these problems. problems. Often in development drilling, enough geologic data is available to justify setting pipe after running only an electric log in open pipe after running only an electric log in open hole. This practice, however, usually leaves hydrocarbon type and volume undetermined in many zones. In order to define the accuracy with which these quantities can be determined in casing with a combination density-neutron (CNL-FDC) tool, 17 zones in a well with good open-hole data were logged in casing and systematically analyzed. The results show that in many cases this method of well evaluation will be a workable alternative to using conventional or even some newly developed open-hole techniques.

A full suite of open-hole log data, if available, remains superior to this approach. However, often conventional porosity and sidewall core tools simply will not reach the objective section in very high angle holes. Also, the advantages of obtaining open-hole porosity data are partially or completely offset porosity data are partially or completely offset by the additional rig time costs and increased risk of losing the hole.

OPEN VS CASED-HOLE DENSITY LOG

Attempts have been made to estimate formation density from cased-hole density logs. In the subject zones, the bit size was 9-7/8 in. and 39 lb — 7-5/8-in. casing was set.
Cluster - A Method For Selecting The Most Probable Dip Results From Dipmeter Surveys
Authors: Hepp V. , Dumestre A.C.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The several curve displacements determined from four-arm Dipmeter surveys can be combined in many ways to obtain formation dip, When the different displacement combinations at a given level do not lead to the same dip value, use can be made of the redundant data from the level, along with data from overlapping adjacent levels, to determine the most probable dip. CLUSTER is a technique for doing this.