bluuebunny/crossref_metadata_2025 huggingface dataset:
3 1/2" Coiled Tubing Completions in PDO
Authors: Al Hookani Said , Churchfield Sean , O'Neill John
Published: December 2007

PDO has established a goal for well technology of being able to drill, evaluate, complete and service multilateral horizontal wells at balance or underbalanced. Reeled systems have a clear potential in this area. A project has been set in place to prove or develop technology to meet this goal. Separate trial programs are underway to investigate the drilling and completion elements required. These will be combined with the results of an underbalanced drilling trial to allow under or at balance operations during each phase of the well's life.

The Coiled Tubing Drilling, Evaluation and Completion (CTDEC) project began in 1993 with a feasibility study outlining the potential benefits of a CT operation. Technical trials to prove the feasibility of the activities began in 1994 with a sequence of 3 drilling trials, and a single CT completion. In 1995, eight 3-1/2" CT completions were run; 4 ESP completions and 4 gas lift completions. Further trials are planned, 2-7/8" slim dual water injectors and 6 velocity strings for gas lift wells. Results so far indicate that the CT operations can be carried out technically. The next phase of the project will be to demonstrate the commercial viability of the activities in both the Drilling and Completion areas before moving to at or underbalance operations. The Drilling Engineering part of the project is continuing with a 15 well sidetracking trial to confirm the economic benefits. The completion project is rounding off the technical trials before establishing further work scope.

This article focuses on the Completion phase of the project.
Integrating Conservation and Development in Papua New Guinea - A Chevron/World Wildlife Fund Case Study
Authors: Henry Don , Grant-Suttie Francis , Price Jim , Fraizer Will
Published: December 2007

Conserving biological diversity and enhancing the well-being of people is a significant challenge for all of society including both the private sector and conservation organizations. This paper describes efforts by the Kutubu Petroleum Development Project (KPDP), operated by Chevron Niugini, and World Wildlife Fund (WWF) to enhance conservation of the rich biological diversity of Papua New Guinea and to assist local indigenous communities with sustainable development. Supported by a grant from the KPDP, WWF is implementing an integrated conservation and development project (ICDP) with local communities in the 2.3 million hectare Kikori River catchment located in the Gulf and Southern Highlands Provinces. The region is characterized by biologically diverse tropical rain forests that provide the predominant livelihood for over 40,000 indigenous peoples. The Kikori ICDP is assisting local people to establish culturally appropriate conservation management areas and to develop eco-tourism, sustainable fisheries, and community based eco-forestry. Detailed biological surveys established the conservation significance of the region, and confirmed the health of the environment. The KPDP is a one billion US dollar capital cost operation which produces Papua New Guinea's first commercial oil reserves. Protecting people and the environment is an essential design and operational criteria for the KPDP. Comprehensive environment and community policies including strict design codes and operational standards, rain forest protection measures, and community business and public health programs are used to minimize the environmental impact and to increase local community benefits. This case study demonstrates the benefits to conservation and local communities of the collaborative efforts of the KPDP and WWF, and the national benefits of a new development paradigm where the economic and environment interests of a nation are considered together.
Use of the SP for Exploitation - Case Histories
Authors: Jasper A. Rex , Isaac Robert L.
Published: December 2007

A method of restoring or normalizing the spontaneous-potential (SP) curve in thick fractured formations is presented. The Restored SP is then used to delineate the best drilling locations or recompletion candidates.

Two case histories are reviewed:

(1) the application in the Marmaton zone in the Oklahoma Panhandle, and

(2) the application in the Woodford zone in South Central Oklahoma.

The Restored SP technique has been successfully applied in the above reservoirs which defy more conventional log analysis. Histories of application to areas of both high and low well density are reviewed.

Introduction

Most engineers and geologists are familiar with reservoirs which defy quantitative log analysis. This is often due to the inability to calculate porosity and to evaluate reserves from porosity and to evaluate reserves from log-derived properties. Shale content and fractures are two of the most common occurrences which render quantitative log analysis useless. We have experimented with the use of the SP curve to empirically evaluate reserves in fractured reservoirs with high shale content. Our approach is based on the generation of the SP being dependent upon some degree of permeability and that economically recoverable reserves are a function of permeability.

A determination of permeability is not attempted but rather an empirical correlation of SP versus reserves. To apply the RSP technique, data must be gathered and analyzed for individual areas. This approach has been successfully used in two areas of Oklahoma to make recommendations to obtain leases, to drill or re-enter wells, and to recomplete wells.
Far-Field Hydraulic Fracture Geometry: A Changing Paradigm
Authors: Mahrer K. D. , Aud W. W. , Hansen J. T.
Published: December 2007

The common viewpoint or paradigm of the far-field hydraulic fracture geometry is changing. Data sets compiled over the last decade are incompatible with the conventional picture of a single, bi-wing, planar hydraulic fracture. These data sets include (1) recovered cores, (2) minebacks, (3) microseismicity, (4) overcores and borehole video, (5) treatment pressure response, and (6) surface tilts, in conjunction with advancements in laboratory simulations, studies of natural hydraulic fracture analogues, and improvements in numerical simulations. The single, planar, far-field fracture paradigm finds its roots and development in early theory and simplified laboratory studies that were predisposed to single, planar fracture geometry. Replacing the old paradigm is a new perspective that includes a strong potential for creating multiple, far-field fractures. The implications of multiple, far-field fracturing has resulted in adjustments to completion and stimulation strategies to address and affect the overall fracture geometry.
Minimum Cost Casing Design
Authors: Halal A. S. , Warling D. J. , Wagner R. R.
Published: December 2007

The casing program of most wells represents a significant portion of the total well cost, approximately between 15 and 35%. Hence, any reduction in tubular cost can generate considerable cost savings. This paper presents a novel and efficient minimum-cost casing design technique which employs a recursive branch-and-bound search method together with a streamlined load generator for complex loading conditions. The three-stage technique utilizes effective bounding methods which substantially reduce the search space and speed up convergence. To illustrate the efficiency of the technique in practical applications, a parametric study is presented for an example well which models a geopressured well in the Gulf of Mexico. The results show that a minimum-cost design for most casing strings in this example can be achieved in less than 2 seconds using a personal computer with a 75 MHz Intel 486DX processor. One key outcome of this research is a Microsoft Windows-based implementation of this technique which offers the casing designer a powerful and flexible tool to quickly assess the trade-off between the potential cost savings from increasing the design complexity and the accompanying increased risk.
Non-Stationary Stochastic Modeling Techniques for Reservoir Description: An Application from the Alaskan North Slope
Authors: Thadani S.C. , Novak M.
Published: December 2007

This paper describes non-stationary (multipopulation) Stochastic Modeling techniques that were developed and used to construct regional average velocity and depth surfaces to the top of a key geological marker overlying several major reservoirs from the Alaskan North Slope. The techniques combine average velocities derived from well data with stacking velocities derived from velocity analyses ("VELANS") of 2D and 3D seismic data. In these techniques, the average velocity field is modeled as a mixture of statistically homogeneous (2nd order stationary) populations that are predominantly consistent with variations in the thickness of a near-surface permafrost layer, and other known geological factors. A multi-population Soft Inversion algorithm is used to infer bounds on average velocities at selected locations (away from existing wells) by statistically calibrating the stacking velocities to the average velocities. Stochastic images of the average velocity field are generated using a new (mixture) Stochastic Imaging algorithm - these images are conditioned to the wells, the Soft Inversion velocity bounds, and to the multi-population spatial correlation model of the data. Finally, seismic travel time measurements are used to convert the average velocity images to depth. The results have been "blind" tested at 30 wells - the results indicate significant improvements in average velocity (and depth) estimation accuracy as compared to conventional interpolation techniques.

Introduction

Seismic depth conversion may be defined as the process wherein seismic travel time measurements to selected geological horizons are converted (or "migrated") to depth using an inferred spatial velocity field. One class of Stochastic Modeling approaches to seismic depth conversion, typically images depth (measured at the wells) and seismic travel time (measured at and away from the wells) as co-variables, using methods such as external drift and Cokriging/Cosimulation. Such methods typically require significant well control for inference of the underlying spatial auto and cross correlation models for the co-variables; the spatial velocity distribution is modeled only implicitly, and local precision of the estimated depth surfaces relies primarily on the conditioning provided by the well control. In many applications, stacking velocities derived from velocity analyses ("VELANS") of 2D and 3D seismic data are readily available. These stacking velocities often correlate with average velocities, and constitute an important (densely sampled) source of "soft" conditioning information away from the wells, which can augment the available well and seismic travel time information in constructing the desired depth surfaces. This has lead to the development of another class of Stochastic Modeling approaches for seismic depth conversion, wherein the spatial average velocity distribution is explicitly modeled and imaged.

P. 67
Improving Management of Oil and Gas Assets Through Derivatives
Authors: Stibolt Robert D.
Published: December 2007

As markets for futures, swaps, and options have grown and matured in the oil and gas industry, the question of how companies should make use of such financial derivatives naturally arises. The simplest models of risk versus return in modern finance theory are based on a world in which the costs of external and internal financing are the same and all risk is either systematic or can be diversified by shareholders. In this simplified world, derivatives must be viewed as purely speculative instruments that can add nothing to shareholder value. However, in the real world of financial distress, imperfect information, and misaligned management/shareholder risk attitudes the use of these instruments can add significant value. This paper explores the sources of this potential for value creation, including a look at improving organizational alignment, information consistency, capital structure, and management of real assets.

A Strategic Decision Perspective on Derivatives

Derivatives have been receiving a great deal of attention recently, both in the financial press and in political circles. This attention has resulted from a number of highly publicized financial catastrophes in which even relatively sophisticated companies have lost millions of dollars. It is understandable that enlightened executives would react to this series of financial catastrophes by avoiding any involvement with these sometimes complex financial instruments. This initial reaction is quite reasonable in that outright speculation in markets not directly connected with a firm's core strategies cannot be justified from a shareholder perspective.

However, further investigation of the problem reveals dimensions that might cause these executives to reconsider their initial reactions. In most cases, derivatives cannot be avoided because they are already embedded in the day to day business of managing a firm's real assets. Examples that cannot be ignored include the valuable mid-month natural gas swing options that producers often give away at no charge to marketers or customers and the option value of undeveloped real assets.

Even as it becomes evident that derivatives cannot be avoided, critical management questions must still be addressed:–Are derivatives just a zero-sum game?–Are derivatives dangerous?

While the first question involves a fuller discussion that comes later, the second question can be addressed immediately. Derivative transactions fall into three distinct categories, only one of which appears to consistently lead to financial trouble. Perhaps derivatives can be used profitably and trouble avoided by better understanding these categories and the types of transactions associated with them.
Separator Design and Operation: Tools for Transferring "Best Practice"
Authors: Lawson P. N. E. , Little L. M.
Published: December 2007

Maintaining flexibility in the design of separation systems is a key consideration in coping with the uncertainty in fluid properties, reservoir performance and production profiles. There is an increasing need to improve our understanding of how different separation schemes perform over a range of operating conditions. This paper outlines two recent approaches that BP Exploration have been developing in the area of separator design and operation. The first addresses the need to understand the ‘operating envelope’ of a separator. In contrast to the conventional method of sizing a separator for a number of design cases, the operating range of a separator can be presented as an operating envelope. This concept will be demonstrated as a potential method for taking account of reservoir uncertainty and as a means of identifying operating flexibility. A parallel development is the construction of a database which captures information on BP Exploration’s Production Separators. In addition to design and current operating data, ‘case histories’, incorporating details on retrofits and design changes, are being collected as a means of transferring ‘Best Practice’ in separator design and operation across the BP Exploration operating Assets world-wide.
The Displacement of Oil from Porous Media by Micellar Solutions
Authors: Sharifi Fereidoon , Osoba J.S.
Published: December 2007

The increasing need for oil in today's world has focused attention on increasing the efficiency of displacing oil from reservoir rock. Recently the oil industry has become interested in oil recovery using miscible fluids.

The purpose of this investigation was to study the effectiveness of micellar solutions in recovery of oil from porous media. The models used were linear sandstone cores, a linear model packed with various sands and a five-spot model packed with various sands and a five-spot model packed with sand. Models saturated with water packed with sand. Models saturated with water and different viscosity crude oil were subjected to micellar solution injection. Experiments were performed for both secondary and tertiary recovery performed for both secondary and tertiary recovery conditions.

One hundred percent oil displacement by micellar solution injection was observed for all but one system. This exception occurred when a small slug of micellar solution was injected into a sandstone core and displaced with a Dow pusher. A small amount of oil was observed at pusher. A small amount of oil was observed at the outflow end of the core when small samples were cut from the core and examined.

The laboratory experiments indicated that micellar solutions are an effective means of oil displacement. These solutions are effective because of their miscibility with the oil, controllable mobility, their stability in the presence of reservoir crude oil, water and rock, presence of reservoir crude oil, water and rock, and finally their incomplete removal of contacted water.

Introduction

Complete recovery of crude oil from an oil-bearing formation is not possible if the crude oil is displaced by an immiscible fluid such as water. Capillary forces retain part of the oil in the pores even though many pore volumes of the immiscible displacing fluid are passed through the system. To recover the oil trapped in the pores, the capillary forces must be zero. There are no capillary forces if the displacing fluid is miscible with the crude oil.

For the past decade the oil industry has been interested in displacing oil from reservoir rock using miscible fluids. The miscible process has been used in fields when technically process has been used in fields when technically and economically feasible.

A few years ago a micellar solution was developed that was miscible with oil and water. In 1967, this solution was described by Marathon Oil Co. To displace oil from reservoir rock, a micellar solution and then water were injected into a formation. The method was reported to result in a 100 percent displacement of oil. Micellar solutions used in this process consisted basically of three components: hydrocarbon, surfactant and water. In addition, a small amount of electrolyte and cosurfactants (e.g., alcohol) were sometimes used.
Laboratory and Field Evaluation of the Role of Drill Solids in Formation Damage and Reduced Horizontal Well Productivity
Authors: Burnett D.B. , Hodge R.M.
Published: December 2007

This paper examines the role of drill solids in causing formation and completion damage in horizontal openhole completions. Drill solids are routinely kept to a minimum in drilling fluids, mainly to improve drilling properties. However, these drill solids, even at low concentrations, represent a significant source of insoluble particulates that become incorporated in the drill-in fluid filtercake. Not only is the potential for formation damage greater, but these filtercakes laden with insoluble drill solids can be deposited on screens resulting in reduced productivity through screen plugging.

The objective of this paper is to illustrate the effect of drill solids contained in drill-in fluids on formation damage and well screen plugging and to emphasize the importance of minimizing solids, not only to maintain the desired drill fluid rheology, but also to effect better filtercake cleanup. New laboratory test methods have been used to study formation damage in a 2-foot long horizontal wellbore model incorporating dynamic filtercake deposition on natural and synthetic core material. The model measures formation damage in radial flow. Formation damage tests with drill solids were performed for both water based and synthetic based drill-in fluids. Testing was also performed to simulate prepacked screen damage using a variety of commercially available drill-in fluids and common resin-coated gravel sizes. Results of these tests with laboratory-prepared fluids have been compared against the performance of field fluids and will eventually be correlated with field well performance.

Background

The use of horizontal wells to maximize recovery of oil and gas has become commonplace. However, operators frequently find horizontal wells do not provide the expected productivity after completion. While cased hole completions exploit perforation techniques to bypass the zone of formation damage caused by drilling, the openhole completions commonly used in horizontal wells do not provide a means of bypassing this damage.

Previous work has discussed formation damage caused by drill-in fluids. Often, these studies have concluded that formation damage is caused by solids invasion into the rock or from damage caused by incompatible fluid filtrate. Some investigators have presented evidence that DIF filtercakes did not penetrate into rock matrices. Fraser's study showed ESEM photo images of different types of DIF filtercakes tightly compacted onto formation rock surfaces. He found very little filtercake invasion in the rock matrix. Burnham and Browne have discussed the concept of "lift off" pressure that can be used characterize the behavior of DIF filtercake on formation rock. Their studies suggest that "formation damage" can be caused by too "tight" a filtercake on rock surface.

P. 749
Gel Formation and Thermal Stability of Gels Made From Novel Water-Soluble Polymers for Enhanced Oil Recovery Applications
Authors: Eriksen O.I. , Daasvatn K. , Vigerust B. , Braen T. , Olafsen K. , Ahmed I. , Moradi-Araghi A. , Hamouda A.A.
Published: December 2007

This paper will describe the details of experimental conditions and will present gelling systems for potential water shut-off and profile modification applications under hostile environmental conditions.

A range of copolymers of acrylamide with an experimental comonomer has been prepared to evaluate gelation of the polymers and thermal stability of the gels under hostile environmental conditions. The experimental monomer was obtained using commercially available chemicals by a simple synthetic route. Gels of high thermal stability have been revealed with polymer concentrations below 1 weight %. The polymer was dissolved with crosslinker in synthetic North Sea water (SNSW). The crosslinking systems include phenol with formaldehyde (HCHO) or hexamethylenetetramine (HMTA). The results were evaluated after aging for 30 days at 120 C. The thermal stability of the gels depends not only on chemical composition of the polymers and the crosslinker, but also polymer and crosslinker concentrations used for gelation. For one of the polymers, viscometric study of gel formation was carried out in addition to the studies of gel stability.

In this work, statistically designed experiments were used to determine which variables had the most significant effect on thermal stability of the gels so that the optimum gelling composition could be determined. These variables include polymer composition, polymer solution viscosity and concentration as well as the crosslinker concentration. A ranking of the gels was made according to an overall gel quality parameter based on gel strength and degree of syneresis. The results illustrate the advantage of using experimental design during testing and evaluation of synthetic polymers.

Introduction

The amount of residual oil can be up to 40–70% in oil producing fields. To increase the production from off-shore fields, sea water is injected into the formations. The sea water follows the high permeability zones in the reservoir, and after some time, a water break-through may occur, and the result is a higher water to oil ratio. In such a case, it is desirable to plug high permeability zones in the formation by using water soluble polymers. Generally, a solution of the polymer along with an appropriate crosslinking system, is injected into the formation. With appropriate placement techniques the polymer solution can permeate into and form gel in the regions having the highest permeability. However, for near-wellbore applications on deep off-shore fields, the salinity and the temperature limit the use of many currently available water soluble polymers for enhanced oil recovery applications in these regions.

Polyacrylamides with phenol/HCHO as crosslinking system have been used successfully for plugging or permeability reduction, but the thermal stability of gels from polyacrylamide is very poor above 90 C in sea water due to extensive syneresis.
Sweep Efficiency in a Two-Dimensional Miscible Slug Injection
Authors: Bieber M.T.
Published: December 2007

A series of laboratory experiments was conducted in which oil was displaced from a porous medium by a solvent slug driven by a porous medium by a solvent slug driven by a miscible fluid.

Two dimensional displacements experiments were carried out on a consolidated porous media representing one fourth of five spot. All fluids were miscible together. Among the variables investigated were slug size, viscosity ratio and sweep efficiency.

Such research with simple fluids was undertaken to provide basic information both for the laboratory study of more complex fluids in the same porous media and for the development of a numerical model capable to predict performance of miscible slug injection.

Introduction

As the amount of oil to be recovered is determined by the fraction of reservoir contacted by the flood the main purpose of all secondary recovery processes now under investigation is to improve the sweep efficiency of the injected fluid.

Sweep efficiency is largely determined by the fluid mobilities so the study of this last parameter is a step towards a better recovery. parameter is a step towards a better recovery. Several processes tend to improve mobility ratio between oil in place and driving fluid, they can act: on injected fluid viscosity,-on in place fluid viscosity, or: on permeability to injected fluid. In order to have a good displacement efficiency and a good sweep efficiency, all the different secondary processes use slug injection.

For miscible processes, a slug will be injected to reduce oil viscosity and mobility ratio between oil and driving fluid will be reduced.

Others recovery processes use non newtonian fluid injection, a slug of polymer solution or of foam will decrease the permeability of the reservoir to a displacing fluid and improve mobility ratio.

In order to investigate the simple physical phenomena related to flow of fluids with very phenomena related to flow of fluids with very different mobilities ratios, we conducted a laboratory research in a two dimensional porous media.

We studied the injection of slugs using simple miscible fluids.
The Theory And Practice Of Monitoring And Controlling Dumpfloods
Authors: Davies C.A.
Published: December 2007

The term dumpflooding usually refers to the technique of maintaining the pressure of an oil reservoir by allowing a high pressure potential water source zone to flow naturally into the oil zone. The reason for using this technique is primarily related to its cheapness both in initial capital expenditure and in the routine operating expenses. This technique becomes particularly important in isolated areas where particularly important in isolated areas where there is insufficient ground water.

There has been a problem in monitoring the rate at which the wells transfer water from a high pressure potential zone to a low pressure pressure potential zone to a low pressure potential zone. This is due to the fact that potential zone. This is due to the fact that there are two zones open to the well bore which cannot be readily monitored independently.

The theory of dumpflooding has been developed and due to the complexity of solving the resultant second order differential equations, a computer program has been written and presented to assist analysts in monitoring the dumping rates.

A technique has also been developed which permits monitoring of the actual fluid injection rate, within an acceptable accuracy, and also permits the determination of well bore properties of both the source zone and the injected zone from simple fluid levels and periodic fluid travel logs.

Introduction

The technique of injecting water into an oil producing reservoir for either pressure maintenance or secondary recovery is a well-established process in the worldwide oil producing industry.

The methods available for obtaining water for injection purposes are numerous and the economics associated with purposes are numerous and the economics associated with the injection project usually dictate which source should be used. The source of water used is dependent usually on the quality and quantity of water available. For instance, the sea or rivers may be used, when available, but treatment costs are often very high. Subterranean water is often of better quality but quantity and/or accessibility usually involve large capital expenditures for wells and pumps.

This paper deals with probably the cheapest and most effective method of injecting water into an oil reservoir, that is, dumpflooding.
Computer directed supervisory control and monitoring in Libya
Authors: Babinec M.E.
Published: December 2007

In early 1970, Oasis Oil Company of Libya put into operation a computer directed put into operation a computer directed Supervisory Control and Monitoring System for the company-operated power generation and distribution, pipeline, and oil production facilities within the Sirte Basin of the Libyan Arab Republic.

A single on-line computer has been installed at a site deep in the Sahara Desert to operate in conjunction with fourteen Satellite Stations, via the company-operated communications system, for control and monitoring of several producing oilfields, five mainline pump stations, ten gas turbine driven generators at four dispersed locations, and a 138 KV power transmission system.

The harsh desert environmental conditions coupled with temperature variations from 30 degrees F to 140 degrees F have presented formidable obstacles for the implementation of this system. The overall system operation, however, has been quite successful.

Details of this particular computer application including performance history and cost information, are given. Various aspects of system software, hardware configuration, input-output devices and the communication links are discussed. Salient design and implementation problem areas are also touched upon.

Introduction

Following a feasibility study, Oasis Oil. Company of Libya decided in December, 1966 to install a computer directed Supervisory Control and Monitoring System to improve coordination of the company's widely dispersed field operations. (See Exhibit I.) This system would centralize collection of basic operational data, monitor and report alarm conditions, and provide remote control of equipment. Besides wide dispersement, factors in favor of computer directed surveillance and control were expansion flexibility and relative ease of computer program modification to match field changes. program modification to match field changes. In March, 1969 the computer system went "on line" and began interrogation and control of the first of fourteen Satellite Stations. Implementation of the system was completed in October, 1971. Three new Satellite Stations were added to the system in January, 1972.
Formation Evaluation Parameters of the Rotliegendes Sandstone, North Sea Area
Authors: Fertl W.H. , Cavanaugh R.J. , Shepler J.C. , Cope B.G.
Published: December 2007

Over the past few years the Permian Rotliegendes Sandstone in the North Sea area has been established as a profilic and fascinating gasbearing formation. Realistic evaluation of major gas deposits accumulated in this reservoir rock requires an engineered use of well logging data and core interpretation on a comparative basis. Permeability relationship, data on cementation factor and saturation exponent, matrix grain density, rock compressibility, etc. are discussed on several field cases.

Introduction

Over the past several years the shelf region of the North Sea has developed into Europe's most promising offshore area of exploration for gas and oil. In rapid succession substantial gas reserves have been delineated especially in the southern region of the North Sea area. This is illustrated by figure 1 showing a generalized map of offshore operation in the North Sea area (Hark et.al., 1971). A corresponding schematic geological profile through the southern part of the British North Sea shelf profile through the southern part of the British North Sea shelf area is given in figure 2 (Hornabrook, 1967).

The so-called Rotliegendes sandstone, or Lower Permian age, has been established as a profilic gasbearing formation of major areal extent, covering large parts of both the North Sea and NW-Europe (Holland, Germany). A stratigraphic table of the North Sea area is given in figure 3 (Heybroek et.al., 1967).

Despite the fact that several hundred wells have been drilled in the North Sea, only limited data have been published on formation properties of the Rotliegendes. Our present discussion attempts to shed some light on our many observations and the problems one may face in evaluating reservoir characteristics problems one may face in evaluating reservoir characteristics of the Rotliegendes using well logging, core analysis, and other laboratory data.
Extended Reach Drilling: Managing Networking, Guidelines, and Lessons Learned
Authors: Judzis Arnis , Jardaneh Kamal , Bowes Colin
Published: December 2007

During the last two years, BP Exploration developed a plan to assure all aspects of Extended Reach Drilling (ERD) opportunities were understood by business units (Assets). A global network of personnel involved in both ERD operations and technology support pursued a structured approach to enhance ERD option selection, well planning, well construction, and performance measures. This led to a successful initiative to develop a comprehensive set of ERD "Guidelines". Experiences from operations worldwide are included in sections ranging from drilling fluids to stuck pipe prevention. The versatility of the Guidelines was in part attributed to its electronic distribution, available either through local network servers or through the company's intranet.

The ERD guidelines focus on well design, planning, and operations. For engineers in the Assets, the guidelines and information provide a basis for determining "what is possible". Well planning is an iterative process to determine the optimal mix of rig equipment, fluid and tubular requirements, drillstring design, and so on. The strategy behind the information in the Guidelines and the transfer of "best practices" by the BP Exploration ERD Network was to support an iterative process by which learning would take place and performance improved. Thus the Extended Reach Drilling Network has provided a method by which ERD achievements and lessons learned are consolidated, and the information necessary for Assets to identify opportunities are available.
Development of a One Piece Liner Hanger/Liner Top Packer/ Production Packer System for Monobore Wells in Alaska's Kuparuk River Field
Authors: Trantham J. A. , Anderson L. F.
Published: December 2007

To meet the need to reduce monobore tubingless injector completion cost, a combination device to hang a liner, seal the liner top, and perform completion packer function with a compact single unit has been developed. This combination system will improve the economic feasibility of the Kuparuk River Field monobore project in Alaska. This paper will describe the current system, discuss the benefit for a single trip completion, present test results, and discuss the running procedures of the single trip multipurpose packer.
Field Specific Analysis Reinforces Role of Bit Technology in Improving Overall Drilling Economics
Authors: Turner E. C.
Published: December 2007

An earlier macro-analysis of more than 100,000 bit records from around the world revealed that technological advancements in PDC bit design and application have contributed to a reduction in global cost per foot an average 35%, while roller cone bit performance improvements have resulted in an 8% drilling cost reduction on average. A new study of field specific bit performance and bit usage patterns further supports the results of the previous study by documenting at a micro level the impact of bit technology on drilling economics.

The impact of improvements in bit technology have significantly reduced drilling costs and increased overall drilling efficiency in both high-cost and low-cost drilling theaters worldwide. Technical advancements have improved both bit life and penetration rates.
World's First 4.5" Coiled Tubing Pipeline
Authors: El Laithy W.F.
Published: December 2007

Coiled tubing is rapidly growing pipeline technology. Utilization of coiled tubing as pipelines is new application to an existing technology. Until recently coiled tubing was used primarily by service companies for coiled tubing workovers. As the technology expanded the industry began using coiled tubing for other applications such as drilling, coring, logging, well clean out operations and artificial lift. As the tubing mills began production larger sizes, it became possible to consider using coiled tubing as pipelines. The application of coiled tubing as a pipeline began in the Gulf of Mexico. The early results supported the application as being a low cost, time saving, economic alternative to conventional welded pipe for flowlines. Coiled pipe applications have been used in 4 to 100 feet of water in the Gulf of Mexico area and the installation techniques have varied significantly.

In 1994, the Gulf of Suez Petroleum Company (GUPCO), a joint venture company between Amoco Production Co. and the Egyptian Petroleum Co. embarked on the first international application of the 3.5 inch coiled pipe using a dynamic lay procedure. The cost savings from the first two jobs were estimated to be in excess of 70% when compared to the traditional lay vessel charges. Engineering design and field experience was shared at the Middle East Oil Show (MEOS 95) in Bahrain during 1995 (SPE 29786). Subsequently Gupco has taken a leading role in the application of coiled pipe technology with the 1996 installations using the first production of 4.5 inch coiled pipe, one of which is a record setting 62,000 FT. high pressure water supply line. Cost savings of this larger diameter coiled pipe are still yielding 55% cost savings over the conventional barge lay techniques. This paper will cover the significant findings of that engineering work and present actual field case histories on Egypt's first 4.5 inch coiled pipeline projects.

Introduction

The Gulf of Suez Petroleum Company has been using coiled pipe technology since 1994. Since that time the technology has grown with larger diameters being offered. These larger pipes have enabled the company to examine additional opportunities in the Gulf.

To date the company has installed 45,000 feet of 3.5 inch and 72,000 feet of 4.5 inch coiled pipe. In 1994 GUPCO embarked on its first two coiled pipeline projects using the 3.5 inch material. By 1995 a new larger diameter coiled pipe was being offered. The 4.5 inch material offered additional application in the Gulf and GUPCO pursued three additional projects. P. 121^
99.9% Sulphur Recovery from H2S Containing Gas Streams
Authors: Savin S. , Nougayrede J. , Legendre O. , Nedez C.
Published: December 2007

Catalytic processes available today for the treatment of H2S containing gases in refineries and gas plants, are limited to an overall sulphur recovery performance that can't exceed 99.7 %. A new process is proposed to reach 99.9 % min. sulphur recoveries, based on the direct oxidation of H2S below sulphur dew point, using a new catalyst especially designed for this application. A first industrial experience is currently on stream.

Introduction

Reducing atmospheric pollution by SO2 has become a major environmental concern for natural gas and oil industries.

The so-called "modified Claus" process has known a wide-spread development for some decades, to recover more and more H2S from acid gas fields and crude oils by converting it into the more environmentally friendly sulphur, according to the following reaction sequences:

In the same time, steadily tightening regulations have nourished the parallel development of improved techniques to help to get the best of the Claus process by acting mainly in two fields:–catalyst developments, aimed at improving Claus as well as COS/CS2 hydrolysis reactions using advanced pure aluminas, increasing the life time of alumina-based catalysts downstream by oxygen scavenging, increasing the overall catalytic activity by introducing the performing titanium dioxide.–process developments, not only to improve the basic Claus sulphur recovery unit, but also to further process the Claus plant tail gas in order to get rid of the maximum of residual H2S.

Totally catalytic routes involving the most up to date catalysts from Sulphur Recovery Unit to Tail Gas Treatment make it possible today to industrially reach an overall sulphur recovery as high as - but not exceeding - 99.7%.

The 99.9 % sulphur recovery performance can be presently achieved only by implementing wet Tail Gas Treatment processes involving a solvent absorption step and subsequent recycling of H2S. Although efficient, these processes are highly expensive, both as regards capital investment and operating costs, and moreover, they generate liquid acid wastes to be treated.

It was decided to try to overcome these two disadvantages by reconsidering the approach of the 99.9% performance through a totally catalytic route. This challenge supposed to basically reconsider both process and catalyst philosophies.

1. Process

A significant breakthrough in tail gas treating was introduced in the 70's with the concept of operating below sulphur dew point. This combined two major advantages:–the enhancement of the formation of sulphur through immediate trapping within the catalyst porous network–the decrease of yield losses in the form of gaseous elemental sulphur.

This concept entails a cyclic operating mode, with the continuous succession of two sequences : an adsorption-reaction phase where the sulphur is formed and remains adsorbed within the catalyst, followed by a regeneration phase where the sulphur is expelled from the catalyst by heating up to 300 C, and recovered by condensing.

P. 233^
Air Toxic Emissions Characterization of Natural Gas Processing Plants
Authors: Ferry K. R. , Gundappa M. , LaCosse J. P. , Shareef G. S. , Johnson K. L. , McCarthy J. M.
Published: December 2007

The U.S. Environmental Protection Agency (EPA) is developing air toxic regulations for oil and natural gas production, with the proposed rule scheduled for promulgation in 1997. The EPA is also scheduled to promulgate air toxic regulations for industrial combustion sources by the year 2000. In addition, several states have air toxic regulatory initiatives that affect the gas industry. Because these regulations could have large economic and operational impacts on the gas industry, the Gas Research Institute (GRI) has initiated a multiphase research program. One of the objectives of this program is to determine potential sources of air toxic emissions in the natural gas industry, the quantities of air toxics emitted, and individual species emitted from typical equipment.

The primary objective of the testing conducted in this program at gas processing plants was to assess potential air toxic and criteria pollutant emissions associated with combustion equipment, including characterizing the following emission sources: internal combustion (IC) engines, gas turbines, incinerators, heaters, and boilers. The pollutant classes evaluated include aldehydes, criteria pollutants, volatile organic compounds, semi-volatile organic compounds, metals, and reduced sulfur compounds. In addition, unit operational data were obtained during testing. To date, eight field measurement campaigns have been conducted at natural gas pipeline and gas processing facilities. Three (3) of these campaigns involved testing at sour gas processing plants, while two (2) other campaigns focused on emission sources at sweet gas plants. The emission test results for these programs are summarized in this paper.

In addition to emissions characterization, the effects of maintenance and performance tuning on emission levels was investigated during one campaign. Results on emissions, efficiency, and cost impacts associated with maintenance and tuning activities conducted on three engines, two incinerators, and two process heaters are reported.
Pipeline and Related Issues
Authors: Lindsey Rhonda P. , Simmons Jerry R.
Published: December 2007

The McGrath Lake oil spill in Ventura County stimulated public concern regarding crude oil gathering pipeline safety. This December 22, 1993 incident occurred from a crude oil shipping line. This spill released an estimated 2,200 barrels (42 gallons = 1 barrel) of crude oil. This oil surfaced and flowed another 1,200 feet into McGrath Lake. The lake is part of a tidal wetland within a large coastal dune system.

One result of this incident was the passage of California Assembly Bill 3261 (O’Connell) as codified in California Government Code Section 51015.05 in 1994. This bill required the California State Fire Marshal (CSFM): establish and maintain centralized database containing specific information and data (pipeline locations, ownership, age, inspection history, etc.) regarding certain crude oil pipelines,conduct a study of the fitness and safety of these crude oil pipelines, andinvestigate incentive options that would encourage pipeline replacement or improvements, including, but not limited to, a review of existing regulatory, permit, and environmental impact report requirements and other existing public policies that could act as barriers to the replacement or improvement of these pipelines.

The following pipelines were included in the data base and study: pipelines for the transportation of crude oil that operate at gravity or at a stress level of 20% or less of the specified minimum yield strength of the pipe; and,pipelines for the transportation of petroleum (crude oil) in onshore gathering lines located in rural areas.
Production Business Planning to Maximize Field Potential
Authors: Ruble D. B.
Published: December 2007

Since 1992, Exxon Company USA’s New Orleans Production Organization has utilized a Business Planning Process to assist with maximizing field potential and improving profitability. The process, based upon Field Level Business Team planning, has allowed NOPO to more effectively identify, resource and implement business opportunities. This paper discusses and provides examples of the processes, tools and results from the Field Level Business Team structure and planning process. The results from the organization, assisted by the process, have been: increased volumes, identification of additional opportunities, >100% reserve replacement, reduced unit expenses, increased profit and return on investment and a focus of our resources on the assets with the greatest potential.