bluuebunny/crossref_metadata_2025 huggingface dataset:
Contract Logistics: A Partnering Approach to Operating Cost Reduction: The Concept and Reality
Authors: Cardale T. A. , Bain G. D. P. , Moody R. G.
Published: December 2007

The control and reduction of operating costs is the most serious management issue facing the oil and gas industry at present, particularly in mature provinces such as the North Sea.

The development and application of the concept of a contract logistics service (CLS) has been timely and pertinent to this need. CLS transfers responsibility for the provision of logistics support from an oil company department to a contractor. The contractor provides a managed logistics service in which resources are shared across its customers and performance measurement is focussed on total operating cost. CLS has now been shown to deliver cost savings in this industry just as it has in others beforehand.

Logistics costs account for about 16% of total operating spend, thus making the field a significant one for generating useful savings.

CLS achieves this through addressing the structure of costs rather than unit costs alone. In doing so it raises issues affecting the current relationships and future structure of major elements of the industry.

CLS has been achieved through a partnering approach involving the creation of an alliance of contractors and operators by the definition of mutual objectives. The experience involved forms a model for cost reduction in the industry that may be more directly comparable to the introduction of partnering in other parts of the supply and service sector than the acknowledged alternatives of offshore maintenance or accounting.

This paper aims to describe the concept and application of CLS; examine the model and discuss the implications.
A Successful Approach for Achieving Lower Operator Well Costs While Providing Potential for Increased Contractor Profitability
Authors: Sears R.W.
Published: December 2007

SPE Member

In order to continue operating in the North Sea, operators must control costs, a big part of which is drilling related in the exploration and development stages. It is important that this control not be achieved at the expense of the drilling contractor, service company or supplier sectors, but rather through greater efficiency and improved performance whereby the operator achieves lower well costs and the supporting function(s) (contractors) improve their potential for increased profitability.

Hamilton Oil Company Ltd have developed a very successful operating philosophy based on the principles of mutual cooperation, total integrated commitment, focused ownership and individual plus corporate accountability. This paper deals with methods which have been used to achieve what are believed to be superior results.

Introduction

The North Sea is recognised as one of the highest cost operating areas in the world. In order to continue their presence in this arena, operators must control costs, a major portion of which is drilling related in the exploration and development stages. Figures 1, 2 and 3 demonstrate the relationship of the crude price with well costs for the past 15–20 years. Well costs have increased significantly while crude prices have remained relatively flat. As the North Sea has become a mature petroleum province, oil and gas discoveries have become smaller and more difficult to explore for, develop, and exploit. Figure 4 shows that more wells are being required to find smaller hydrocarbon reserves.

Hamilton Oil Company Limited (HOCL) as an independent operator produced the first UKCS oil in 1975 from two subsea wells in the Argyll field using a converted semi submersible drilling rig as a floating production facility (FPF). HOCL has continued this innovative type philosophy throughout the exploration/development phases of the Esmond, Ravenspurn North and Crawford complexes as well as in the current forwarding planning for the Liverpool Bay development of the Hamilton, Hamilton North, Douglas and Lennox fields. Several schemes or variations there of are being used or have been considered for achieving the stated operator objective of lower well costs.

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Lifting at the Limit: The Design of Today's Large Liftable Jackets and Integrated Decks
Authors: Smith M. T. , Ray M. G. W.
Published: December 2007

With the advent of a new generation of increased capacity semi-submersible crane vessels (SSCVs) in the 1980s (the DB102 and the M7000), new concepts in twin-crane lift installed jackets and integrated decks began to emerge. During the late 1980s projects such as Veslefrikk, Gyda and Kittiwake took advantage of the increased lift capacity available. Whilst each of these projects broke lift records, the SSCV lift capacities were not fully utilised. However, in the early 1990s lifting at the limit has really come of age.

This paper critically examines the close correlation between installation vessels and the trend towards larger and heavier lifts, especially for integrated decks. The limitations of the SSCVs are reviewed, and the basic methods of "tailoring" jacket and deck design to maximise the SSCV lift capacities are identified. These methods are then reviewed and questions raised for the future.
Surface Lateral Tree for North Sea Platform
Authors: Omsberg N. P.
Published: December 2007

This paper describes the design features of a surface lateral tree and compares the design with a conventional Christmas tree. A lateral Christmas tree is defined as a tree which has no valves in the vertical bore of the tree, and flow through the tree is controlled by valves on the lateral or horizontal bore of the tree. Preliminary evaluations indicate that the use of a surface lateral tree can enhance well intervention procedures, reduce wellhead/tree height, reduce maintenance requirements, and reduce overall risks.
A New Method for Removal of Oil in Produced Water
Authors: Rye S. E. , Marcussen Esben
Published: December 2007

Produced water represents an increasing part of the total production from the process centres in the Danish part of the North Sea. Experience gained with treating the increased volume of water led the operator, Maersk Oil and Gas, to evaluate the possible application of centrifuge technology.

In the produced water from the Tyra formation, the size and distribution of oil droplets were found to be of a character that conventional treatment equipment would have difficulties in separating efficiently. After having tested a rented centrifuge for one year on the Tyra West installation, it was decided to purchase centrifuges for permanent installation on both Tyra East and Tyra West.

At the end of 1992 and beginning of 1993, the 12,000 BWPD centrifuge skids were installed and commissioned on each of the platforms.

Experience from the installation, commissioning and first 6 months of operation has been encouraging. No major problems arose from the integration of the quite complicated equipment and control system with existing installations on the platform. The complete produced water treatment plant modifications were minimal due to the relative simple requirements from the various tie-in points on the centrifuge skid.

The oil in water measurements of the cleaned water out of the centrifuges comply with the Paris convention requirement of maximum 40 mg/l, usually with a large margin. A comprehensive PLC control and communication system to the Platform Control Room performs as planned. The monitoring features available have shown to be beneficial in achieving uninterrupted centrifuge operation. The application of centrifuge technology has shown to be environmentally valuable as well as a very effective way of treating produced water which contain small oil droplets.
Beryl Reservoir Management Study: The Solution of a Complex Problem
Authors: Grant I. C.
Published: December 2007

Despite several prior unsuccessful attempts to simulate the Beryl Formation in the Beryl Field, one of the North Sea's most complex, an integrated reservoir management study was initiated in 1990 which has shown that modelling such a field can be successful with worthwhile results. The conclusions from the study have led to a new understanding of the displacement mechanisms in the Beryl Formation, and have resulted in a change to the depletion strategy under gas export. The impact on volumes and reserves has been significant.

The first successful history match on Beryl was achieved by the integration of new interpretations of reservoir structure and stratigraphy, the results from a conceptual model developed from the analysis of fluid movements and pressure regimes, and a good approximation of the depth-dependent fluid properties into a coarse grid full-field reservoir simulation model. The model exceeded its initial goals, and with subsequent enhancements has been able to provide answers to more detailed questions than considered possible at the outset of the study.

This paper describes the methodology and techniques used to ensure the success of the present reservoir management study, the importance of data acquisition, and how the present simulation models will be further developed and applied to ensure the optimal depletion of the Beryl reservoirs. It also discusses how the scope of the project has been broadened to provide a means for the evaluation of marginal satellite field developments through the Beryl infrastructure, thus providing the necessary tools for optimising the use of the Beryl complex by modelling the multiple reservoirs and future satellite developments as a fully integrated system.
Application of Pseudo-Relative Permeability Curves in a Front-Tracking Simulator
Authors: Nyrønning H. H. , Hove Kjetil , Rian D. T.
Published: December 2007

A new method for generating pseudo relative permeability curves and its applications in a high accuracy front tracking simulator is presented.

The method is applied on 3 different cases, which all gave good results. The different cases consisted of homogenous and inhomogeneous horizontal reservoir models.

The results using a front tracking simulator were more accurate than the results presented by Nyrønning [1], using a finite difference simulator.
East Leman Unit Platform Simplification Project
Authors: Avery B. E. , Downes Anthony
Published: December 2007

Current modifications will dramatically reduce the complexity of the East Leman Unit production platforms. They include by-passing all the major processing facilities on the platforms and installing new utility packages to support an unmanned operation. This has enabled the frequency of platform visits and the cost of future maintenance to be minimised.
Fracture Stimulation of a Horizontal Well in a Deep, Tight Gas Reservoir: A Case History From Offshore The Netherlands
Authors: Baumgartner W. E. , Shlyapobersky Jacob , Abou Sayed I. S. , Jacquier R. C.
Published: December 2007

AME-204 is a horizontal well with two hydraulic fractures draining a Rotliegendes sub-block of the Ameland East reservoir located offshore the Netherlands. The reservoir in this part of the field is of poor quality, with a strong diagenetic impairment caused by kaolinite leading to low matrix permeability (0.2 – 1 mD). Economic development of this part of the field is hampered by the low well productivities.

This paper outlines the screening process which led to the decision to develop this sub-block with a multiple-fractured horizontal well and describes the well configuration chosen. Completion and stimulation designs are discussed in some depth, including selection and laboratory testing of fluid systems and fracture initiation. Additionally, the use and design of pre-stimulation injection tests and proppant pills to reduce near wellbore restrictions are shown.

Practical considerations in the execution of stimulation treatments in horizontal wells are covered. Actual and predicted production performances are compared. The actual productivity improvement achieved over a deviated unfractured well is estimated a minimum factor of 4 at only 30% higher cost. The paper concludes with recommendations for similar projects in the future and also looks at the impact on the development of hitherto economically submarginal fields.
Resistivity Index From Non-Equilibrium Measurements Using Detailed In-Situ Saturation Monitoring
Authors: Jing Xu-Dong , Gillespie Alisdair , Trewin B. M.
Published: December 2007

This paper presents a new method for determining resistivity index from non-equilibrium desaturation tests, where the detailed saturation distributions are measured accurately from X-ray scanning. The effects of uneven saturation distribution along core length are taken into account using a finite-element mathematical model. This new method applies to both Archie rocks and a wide range of non-Archie rocks (i.e., rocks showing non-linear log(l) vs. log(Sw) relationship). It is far less time-consuming compared with other reliable method and it is applicable to both water wet and non-water wet rocks.

Two examples of resistivity index measurements by rapid constant-rate oil injection are presented to demonstrate this new method. The measured data included the apparent resistivity index, which was not representative of the rocks due to the uneven saturation distribution, and the detailed saturation profile versus space and time. The measured resistivity and saturation distribution data were then input into a finite-element model to calculate iteratively the intrinsic resistivity index curves which would be measured directly if a uniform saturation distribution existed. A simple generalised (I vs. Sw) functional relationship has been proposed and used in this paper in addition to the conductive rock matrix (CRMM) model. Both models reduce to Archie model when additional conductance term is equal to zero. Resistivity index curves of the same samples were also measured using the equilibrium method of sleeved oil/brine porous plate desaturation. The resistivity index data from the new, fast non-equilibrium method agree with that obtained from the sleeved oil/brine porous plate method.
A "Quick Look" Approach to Modelling Porosity Trends From Southern Gas Basin Seismic Data in the Hewett Zechsteinkalk Formation
Authors: Milner P. A.
Published: December 2007

The mature Hewett Field area in the Southern Gas Basin has recently been the subject of escalated development targeted at a carbonate reservoir, the Zechsteinkalk. This gas reservoir is located at some 4600 ft TVDSS and has both variable porosity and permeability. In order to address the fundamental requirement of defining porosity distribution within the Zechsteinkalk between wells, seismic modelling has been conducted.

A large suite of synthetic seismograms, based not only on actual, but also on altered logs has been used to simulate the acoustic response of various layer thicknesses, and porosities positioned differently within the carbonate section. This simulation is known as Incremental Pay Thickness modelling. The results, together with the ties between well and seismic data, show the models to be usable on a purpose shot seismic survey.

By producing a work-station derived set of Zechsteinkalk amplitude maps, and conducting local character analysis, a proposed drilling target was identified as a poor location. Three good locations were postulated, based on the modelling and amplitude mapping, and subsequently drilled. Well results show the method to be successful in predicting porosity within the Zechstein to within +/− 3pu.

The amplitude maps have also been used quantitively to provide porosity data for volumetric gas-in-place calculation. The gas-in-place results are compatible with volume predicted from reservoir engineering pressure data.

In view of the drilling success, contribution to reserves definition and quick turnaround to run Incremental Pay Thickness modelling, it is concluded that the method should be considered for North Sea porosity studies, where immediate and reliable results are required.
Organizing for Performance
Authors: Massad A.H.
Published: December 2007

Massad, A.H., Member AIME, Mobil Oil Corp.

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 discussions may be presented at the above meeting and, with the paper, may be considered for presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. publication in one of the two SPE magazines

The ability of an industry or particular company to carry out a Management Development Program is not developed overnight, Program is not developed overnight, or in the short term. Management development is a never-ending program that must be given constant attention by top executives for it to be successful. Further, such programs must be successful if we are to programs must be successful if we are to meet the insatiable demand for managerial talent existing in the future, as well as to prepare the individual to manage for the future.

Many papers and speeches have been written and numerous speeches given on the subject of "Organization". From all of this previous effort we may fairly well conclude there is no set pattern for success in this specific arena. The organizational approaches that have proven themselves most effective over the long run are those with a built-in capacity to adapt to change. However, one thought always comes through as we study the problem. That thought relates to mobilization of people and their impact on the future. To organize for the future, then, means to set up a system that can respond to change and, at the same time, capitalize on it. With this in mind, it may be preferable to dwell on the broader aspects of development of executive and managerial talent and what we consider to be the most critical problem or organizing and managing for the future.

In the past 20 years, the oil industry has experienced expansion and growth unparalleled by many industries in modern times. We not only developed a highly efficient, strong industry in the United States, but exported this same ability overseas to both developed and developing countries, infusing our knowledge into their basic learning process and witnessing a similar growth of the industry in those many areas. This "transplant" not only became the catalyst for economic growth in the individual countries, but also resulted in the development of many top-rated executives and managers from within the individual countries.

Certainly, the ability of an industry or a particular company to carry out such a particular company to carry out such a management development program is not developed overnight, or in the short term. Management development is a never-ending program that must be given constant attention program that must be given constant attention by top executives within a corporation if it is to be successful.
A Study of Particulates Migration in Gravel Pack
Authors: Bouhroum Ahsene , Civan Faruk
Published: December 2007

Existing geometrical gravel-pack design criteria do not consider the effect of sand migration through and clogging of the gravel-pack matrix. Therefore, a visual and qualitative laboratory investigation of moving particulates through gravel-pack confined within a parallel configuration (linear) and a convergent configuration (radial) visual cells, has been carried out. Castings of the clogged gravel-pack have been studied to obtain information about the geometrical alteration and deposition morphology. The structural changes due to the clogging process have been characterized by injecting a NaCl-tracer and by analyzing the breakthrough curves (BTCs) before and after clogging.

Results indicate that the migration of particulates into the gravel-pack is a time dependent process which is completed when a self-filtration zone of intruded fine particulates is formed next to the interface of the gravel-pack-particulates at a given flow rate. The particulates migration process is characterized by a discontinuity of particulates concentration. The concentration of particulates is high up to a well-defined line located at the interface. Ahead of the front, there is very little or no particulates at all. It is further observed that an empty pore just ahead of the moving front of particulates remained almost entirely empty until the concentration of moving particulates within the pore immediately behind it is sufficiently high. In this way, the well-defined front of particulates moves through the gravel-pack, conquering pore after pore. It is shown that dispersion measurement characterizes the changes in the structure and therefore in the flow pattern accurately. Tracer analysis indicated that the clogging process created multiple flow paths manifested in highly tailed breakthrough curves.

Besides providing the parameter values for models, these observations indicate that it is necessary to consider a collective motion of particulates instead of the classical particle-by-particle approach used in phenomenological models.
Formation Damage Studies on Reservoir Rocks Using Water-Base and Oil-Base Muds
Authors: Tovar Jose , Azar J. J. , Lummus J. L. , Sarma D. S. , Pilehvari Ali
Published: December 2007

An experimental study was undertaken to investigate the mud solids and filtrate invasion in reservoir rocks while using drilling muds. The objective of these experiments is two fold: one is to evaluate the performance of various reservoir rocks and select the most compatible drilling fluid, and second is to delineate the pore blocking mechanism that causes formation damage. Core plugs of Berea sandstone, dolomite and limestone were examined by petrographic methods and tested for permeability reduction during mud circulation. Both of water-base and oil-base muds that are typically used in field studies were obtained and tested for their performance evaluation.

Data from these tests shows that particles from these drilling muds penetrated well into the interstices of the formation, causing a significant reduction in absolute permeability of the rocks. Higher the initial rock permeabilities of the rocks, higher and much deeper were the impairments. An average reductions of 50 to 80% of oil mobilities were found in case of Berea sandstones when exposed to various muds. In cases of light formations, like limestones tested here, reduction in oil mobilities were found to be 30 to 40%. The location and extent of damage, also varies with other parameters such as mud annular velocity, differential pressure, characteristics of the rock as well as the characteristics and composition of the mud filtrate and solids that flow with it under dynamic conditions. A mechanism of permeability reductions in reservoir rocks is proposed based on the filter cake properties and the test data. Effective guidelines for selecting a proper drilling mud can be obtained as an outcome of this work.
Underbalanced Drilling: Formation Damage Control During High-Angle or Horizontal Drilling
Authors: Shale L. T.
Published: December 2007

Because underbalanced drilling creates a natural tendency for fluid to flow from the formation into the borehole, successful underbalanced drilling depends on appropriate selection of circulating fluid. Under these conditions, use of conventional mud systems often results in lost circulation, formation damage, high mud costs and a need for expensive completions. Use of compressible fluids, on the other hand, can inhibit or eliminate many of the problems associated with drilling in environments in which formation damage is likely.

Use of a compressible fluid in the circulating system, referred to as air drilling, lowers the downhole fluid pressure, allowing drilling into formations where loss of circulation and damage to productive formations are problems of major concern.

Other advantages to air drilling include increased penetration rates, improved drill bit performance, and contamination-free drill solids for ready detection of hydrocarbons.

Reduced pressure air drilling techniques include not only gas continuous phase methods and use of dry gas and gas mist, but also gas internal systems with stable foams and aerated fluids.

This discussion of problems related to underbalanced drilling addresses types of drilling equipment used, and provides an overview of experience gained from both successful and unsuccessful wells.
Control of Fines Migration: A Key Problem in Petroleum Production Industry
Authors: Rahman M. S. , Rahman S. S. , Arshad Aziz
Published: December 2007

Prevention of formation damage due to release and deposition of fines in reservoirs is important to enhance oil production. It is, therefore, essential to know the critical conditions at which particles release and plug the pore channels. This paper presents a physical model of the process of particle deposition in porous network based on a novel experiment in which suspensions of particles were passed through micro capillaries of different diameters [60 and 100 μm] at different velocities and the rate of particle deposition and consequent pressure build up were monitored. An improved 3D trajectory analysis was developed and it was validated by observing the rate of particle deposition in a micro capillary while injecting bentonite suspensions at different velocities and particle concentrations. A criteria is proposed to predict the critical conditions for particle deposition in a micro capillary.
Control of Formation Damage by Modeling Water/Rock Interaction
Authors: Bazin Brigitte , Souto Esperanza , Thiez Piérre Le
Published: December 2007

Modifications of flow properties may be observed when injected brine replaces formation water, especially when the salinity of the injected brine is lower than the resident one. This is generally attributed to detrimental physico-chemical rock/fluid interactions such as ion exchanges. This paper concerns ion exchange mechanisms related to permeability damage.

A laboratory study conducted in batch and flow conditions relates the permeability reduction to the physico-chemical rock interaction. Batch experiments aim to determine the Critical Salt Concentration (CSC) for clay deflocculation. Flow experiments show the effect of pH and water composition on the permeability reduction in a transient region resulting from ion exchanges. These experiments are represented by a flow model involving ion exchange, CSC and permeability reduction. The modeling of the physico-chemical interaction in flow conditions compares very well with experimental results in a wide range of situations.

A 3D chemical model including two phase flow and physico-chemical equilibria is presented for extrapolating laboratory data to reservoir scale. The numerical study evaluates the effect of the composition of both the resident brine and the injected solution on the resulting properties of the reservoir.

The conclusions obtained from the simulations enabled us to deduce different strategies for optimizing well treatment or water injection. It is shown that detrimental permeability effects can be avoided by adjusting the water compositions.
Phosphonate Scale Inhibitor Adsorption/Desorption and the Potential for Formation Damage in Reconditioned Field Core
Authors: Jordan M. M. , Sorbie K. S. , Jiang Ping , Yuan Ming Dong , Todd A. C. , Hourston K. E.
Published: December 2007

Scale inhibitor "squeeze" treatments are used extensively to control problems with downhole carbonate and sulphate scale formation. The return curve from an adsorption/desorption squeeze is governed by the inhibitor/rock interaction which, in turn, is described by the adsorption isotherm. Several factors, such as pH, [Ca2+], temperature, rock mineralogy etc, affect the adsorption level and the shape of the adsorption isotherm. However, these same factors may also lead to deleterious effects in terms of both formation damage and inhibitor solution effectiveness; the latter effect is referred to in this work as "fluid damage".

In this paper, results and discussion are presented on the potential for formation damage and inhibitor fluid damage when acid phosphonates are applied in clastic reservoir formations. Results are presented from an extensive series of phosphonate (DETPMP) scale inhibitor core flooding experiments using Brent Group (North Sea) sandstone cores as the adsorbing substrate. Careful effluent analysis along with detailed petrography and permeability measurement before and after core flooding are shown to be invaluable in assessing the degree of formation damage (and "fluid damage") arising due to several factors. Most of the points raised here are quite general and they are illustrated by the specific field results. This work therefore contributes to the development of safer field applications of scale inhibitor squeeze treatments in the light of individual reservoir petrography.
Produced Water Re-Injection; How Clean is Clean?
Authors: Coleman J. R. , McLelland W. G.
Published: December 2007

A frequently asked question concerning the re-injection of produced water is: ‘How clean must the water be to avoid injection well plugging problems?’ Over the years, industry has developed several techniques to establish cleanliness specifications.1-5 These techniques include both on-site coreflood studies as well as laboratory investigations. The specifications derived from these tests often include maximum allowable values for the content of solids and residual or emulsified oil in the water. Recent field and laboratory studies indicate that two of the most widely used specifications, oil-in-water and total suspended solids, may not provide the best indication of whether a produced water will or will not plug a target formation.

Field data suggest that the plugging characteristics of a produced water may better be defined by the term Total Filterable Solids. This term treats suspended oil as a solid rather than a liquid. The field data also shows that there was no increase in plugging frequency even after an unexpected and significant increase in the oil content of a produced water system at Prudhoe Bay, Alaska.

Laboratory studies, which correlate with field experience, are also presented. The laboratory studies show that produced waters containing relatively high concentrations of oil-in-water can be re-injected as long as the oil droplet size is less than or equal to the average pore throat diameter of the reservoir. Furthermore, these lab studies show that it is important, when developing new produced water specifications, that core flood experiments be conducted on cores at residual oil saturation rather than brine or water saturated cores.
Formation Injectivity Damage Due to Produced Water Reinjection
Authors: Hsi C. D. , Dudzik D. S. , Lane R. H. , Buettner J. W. , Neira R. D.
Published: December 2007

On-site coreflood experiments were conducted at Prudhoe Bay field, Alaska using side streams of produced water taken directly from produced water injection (PWI) lines. The objectives were to determine how rapidly the formation injection face is plugged by produced water re-injection, the location and mechanism of damage, and the impacts of bacterial growth on the extent and rate of damage.

In core tests where produced water was not filtered prior to injection, 90% permeability damage occurred within 24 hours of injection startup. This is inconsistent with field observations where injection well decline is observed to occur over weeks or months, when seen at all. Field observations are consistent with previously-described (growing) thermal fractures that dominate injection performance, thereby minimizing deleterious effects of sand face plugging.

In core tests where produced water was filtered, little damage was observed; this demonstrates that removable components in produced water are responsible for face damage. However, when cores were first inoculated with bacteria-laden water and then flooded for several days with filtered produced water, deep damage (inches) was seen. This suggests PWI wells can suffer injectivity damage over time due to bacterial growth.

Once damage had occurred, addition of biocide did not restore permeability.
Development of an Expert System for Water Control Applications
Authors: Wu F. H. , Chiu T. J. , Dalrymple Dwyann , Dahl Jeff , Rahimi A. B.
Published: December 2007

Accurately diagnosing and treating a water control problem can often be costly and difficult. Although numerous water control products and treatments are available, only a small percentage achieve the desired results because the problem was misdiagnosed, the incorrect treatment design was chosen, or operational problems occurred.

A knowledge-based expert system is now available that can help identify possible problems and provide a complete treatment design. Since the knowledge required in this case may involve some uncertainty, a set of numerical probabilities must be used to represent this information. In addition to the rule-based reasoning1 commonly used by many expert systems, this system includes a unique matrix technique that can use available reservoir, production, and injection information to diagnose problems based on probability.

After identifying all potential problems, the system can recommend the most effective treatment for each type of problem, provide an optimum treatment schedule, and introduce the best placement technique based on available data. This type of expertise can be best represented by production rules. The system also features an extensive explanation facility to help the user understand why each recommendation was made.

This PC-based system can operate in a Microsoft® Windows™ environment. Unlike previously designed systems2requiring an AI shell, C language was used to develop this system.

This paper will address the various design considerations involved in developing this knowledge-based system. Specifically, it will discuss the following topics:

the knowledge acquisition process knowledge representation and system implementation, including – problem identification/reasoning (using the matrix technique) – fluid selection/placement techniques (using the rule-based technique) the operation of the user interface
Reservoir Management of the Fullerton Clearfork Unit
Authors: Bane R. K. , Parker R. A. , Storbeck W. G. , Sunde R. L.
Published: December 2007

The Fullerton Clearfork field, Andrews County, Texas, was discovered in 1942 and waterflooding was initiated in 1956. Field development continues through infill drilling, injection conversions, and add-pay workovers. Recent reservoir management efforts in the Fullerton Clearfork Unit have concentrated on improving workover and drill well economics, and optimizing waterflood performance. This paper discusses techniques that have been developed to identify potential thief zones, improve perforation selection in workovers and drill wells, balance waterflood patterns, and optimize location selection for new drill wells. The flood balancing techniques described in this paper have been implemented in a test area and results from this test will be discussed. Results from recent workovers, conversions, and drill well programs will also be discussed.
Analyzing Well Logs from the Montoya Lime Using a New Carbonate Well Log Interpretation Procedure
Authors: Walsh J. W. , Brown S. L. , Asquith G. B.
Published: December 2007

Analyzing well logs from carbonate formations is difficult because of the problem in estimating the cementation exponent (m) and calculating correct porosities in complex lithologies. Generally, determining lithology can be accomplished using multiple porosity crossplots. If the pore type is known or can be determined from well logs, m can be calculated more accurately using variable m models based upon pore type. A series of logging crossplots can be used to determine the appropriate pore type. Whether the zone is wet or productive can be estimated through the use of several hydrocarbon indicating crossplots. This paper outlines the general analysis for carbonates including estimating lithology and pore type, determining hydrocarbon presence, and computing porosity, m, water saturation, and net pay. An example from the Montoya Lime illustrates the procedure.
Oil or Fresh Water? A New Through-Tubing Measurement to Determine Water Saturation
Authors: Streeter R. W. , Hogan G. P. , Olson J. D.
Published: December 2007

This paper presents log examples and describes the use of Cation/Oxygen ratio (CATO), a Carbon/Oxygen type measurement, to discriminate fresh formation water or water of varying salinity from oil. Instead of using the ratio of carbon to oxygen (C/O), CATO is the ratio of all inelastic gamma rays except those from oxygen, to the oxygen inelastic gamma rays. CATO responds to the presence of oil similarly to C/O, but has several advantages:

(1) CATO can be recorded using a combination 1⅝" Pulsed Neutron Decay-Inelastic gamma ray tool that uses Sodium Iodide crystals, (2) Variations in lithology have much less effect on water saturations, (3) Statistical fluctuations are significantly reduced, (4) The sensitivity to oil is an order of magnitude greater, and (5) Logging speeds are increased to 8 to 12 feet per minute.

Log examples are from sandstones and carbonates and include CATO responses in water floods with unknown water salinity and from formations with low salinity connate waters. Production and test results are also presented. Operating limitations of the technique are given.
Depth of Investigation for Hydraulically Fractured Wells: Field Applications
Authors: Lio Yizhu , Lee W. J.
Published: December 2007

This paper presents two examples to illustrate the uses of "depth of investigation" for hydraulically fractured wells in oil and gas reservoirs. Both high and low conductivity fractures are represented. We present calculations of depth of investigation for hydraulically fractured wells. We examine reservoir pressure distributions at different flow times.
Laboratory Flow Tests Used to Determine Reservoir Simulator Foam Parameters for EVGSAU CO2 Foam Pilot
Authors: Chang Shih-Hsien , Grigg R. B.
Published: December 2007

This paper presents the results of laboratory foam tests that will be used to determine foam parameters for use in foam-flood reservoir simulators. Foam tests were performed at average reservoir conditions of 101 °F and 2100 psig with EVGSAU cores. Foam was generated in situ by simultaneous injection of surfactant solution and C02 into a brine-saturated core. In this study, the gas-liquid volumetric injection ratios of 2, 4, and 6 (with foam qualities of 66.7%, 80.0%, and 85.7%, respectively) were examined. The flow rate in terms of total interstitial velocity varied from 0.36 to 34.38 ft/day. The surfactant was tested at concentrations of 1000 and 2500 ppm active.

The resistance factor of each test ranged from 3 to 63, indicating that foam was generated at all the testing conditions. Brine permeability, which changed after each foam test, had a significant effect on the calculation of foam apparent viscosity. Because of varying brine permeability, the resistance factor data is more suitable for simulator input than the apparent viscosity data.
CO2 Huff 'n' Puff Field Case: Five-Year Program Update
Authors: Miller B. J. , Bardon C. P. , Corlay P.
Published: December 2007

CO2 Huff 'N' Puff has been used on a shallow light oil field to add value to existing oil producing wells by increasing the ultimate oil recovery. Testing was initiated in 1985 with a more continuous program starting in 1989.1 The application of CO2 Huff 'N' Puff has increased oil production 180,000 bbls above the primary recovery with the use of 210 MMCF (12,200 tons). The CO2 treatments have been relatively small with 390 treatments performed on 240 wells.
North Dollarhide (Devonian) Unit: Reservoir Characterization and CO2 Feasibility Study
Authors: Kovarik M. J. , Prasad R. K. , Waddell Wade , Watts George
Published: December 2007

In order to implement a CO2 flood in the North Dollarhide (Devonian) Unit (NDU), detailed reservoir characterization and engineering studies were prepared using 3-D seismic, classical geology and reservoir engineering, and a fieldwide reservoir simulation. Routine and special core analyses, PVT analyses, and well tests taken during recent development aided in the reservoir and fluid characterizations. A black oil reservoir model matched available production and pressure history of the reservoir, and forecasted future production under water injection and CO2 injection using mixing rules developed with the aid of a 1/4 5-spot compositional model. History matching presented a special challenge since Devonian and uphole Clearfork production was commingled between late 1970 and 1990, and therefore actual Devonian production and pressures were not implicitly known.
Foamed Cementing Technique for Liners Yields Cost-Effective Results
Authors: Pickett S. L. , Cole S. W.
Published: December 2007

This paper details the application of a constant density foamed cement technique for liners. The liners were approximately 6200' in length. The liner top was at 4400' and extended to TD at 10,600'. Most of the liner cement consisted of a 9.0 lbm/gal foam. The mud column above the liner had a density of 8.7 to 9.1 lbm/gal. It was demonstrated that relatively long columns of foamed cement could be accurately placed and remain stable in a liner cementing situation. The cement jobs took place on 15 wells during 1991 and 1992. An improvement in cement quality and a reduction in costs resulted from using this cementing technique.
Geological and Engineering Assessment of Remaining Oil in a Mature Carbonate Reservoir: An Example From the Permian Basin, West Texas
Authors: Holtz M. H. , Major R. P.
Published: December 2007

The Jordan (San Andres) reservoir is composed of approximately 400 ft of upward-shoaling subtidal to peritidal carbonate strata that are thoroughly dolomitized and partly cemented by sulfate minerals. The reservoir is divided into four flow units on the basis of depositional facies and subsequent diagenetic alteration. Delineation of these flow units is based on the relationship between open-hole wireline log response and rock mineralogy.

Cumulative production is 68 MMSTB of 218 MMSTB original oil in place, which is a recovery efficiency of 31 percent. Forty-seven MMSTB of remaining mobile oil occurs as bypassed oil in the contacted upper part of the reservoir, which has been penetrated by well bores, and 12 MMSTB of mobile oil is in the uncontacted lower part, which has not been penetrated by well bores. The most prospective areas for increased production by waterflood profile modification in the contacted part of the reservoir are the southwest corner of the field, in low-permeability Flow Unit B, which is incompletely swept, and the eastern central part of the field, where heterogeneous permeability in Flow Unit D has resulted in an incomplete sweep. The most prospective areas for increased production through well bore deepening into the uncontacted part of the reservoir are the southeast corner of the field, where high-permeability Flow Unit C is uncontacted, and the central part of the field, where high-permeability Flow Unit A is uncontacted.

This reservoir contains 113 MMSTB of oil residual to waterflood, and reservoir properties meet preliminary screening criteria for effective carbon dioxide flooding. Thus, this reservoir is a candidate for enhanced oil recovery operations.
Application of Hydraulic Fracturing Technologies, San Andres Formation, New Mexico
Authors: Martinez A. D. , Ellis P. D. , DeAragao D. D.
Published: December 2007

The paper will describe the hydraulic fracturing technologies that have been applied to San Andres formation over the past two years. The use of known fracturing technologies that have been applied include minifrac analysis, fluid quality control, and the use of resin coated proppant to control proppant flowback. In addition the application of real-time fracture analysis and the use of point-source perforating will be discussed.

Results indicate that a fully integrated hydraulic fracturing well completion program can lead to improved production. These results are enhanced by incorporating various in-house departments with various departments from a single source supplier. In this way an integrated team approach is established.
Transporting Mobility Control Agents to Thief Zones
Authors: Irani C. A. , Easterly R. A.
Published: December 2007

This paper will present experimental results that demonstrate a novel plugging mechanism for improving the areal sweep efficiency for EOR solvents such as carbon dioxide or light hydrocarbons, or mixtures of the two. Early gas breakthrough due to thief zones or gas override is the single most significant factor affecting the sweep efficiency of miscible gas processes. WAG is routinely used and foams are being investigated for diverting gas to upswept zones. Both approaches require injecting an aqueous phase which leads to water blocking and slows gas injection, thus delaying oil recovery. Additionally, foams have a short life, are limited to near-wellbore applications due to surfactant during every cycle of surfactant injection.

The optimal solution calls for a deep penetrating plugging agent carried in the solvent phase for accurate and economical delivery to thief or override zones. Additionally, the process should be simple, safe in the wellbore region, robust, and easily activated. It has already been demonstrated that cosolvents like toluene will successfully solubilize polydimethylsiloxane-type polymers in CO2, and that polymer solubility decreases with increasing temperature and decreasing pressure. Consequently, it is feasible to define a polymer + cosolvent combination that is homogeneous at the lower temperature of the injector, but will destabilize as the injected slug moves through the formation and is subjected to higher temperatures and lower pressures.

Figure 1 represents the solubility phase boundary for a 600,000 cst polydimethylsiloxane polymer in CO2- toluene mixtures as a function of temperature, pressure, and two cosolvent concentrations. For either cosolvent concentration, a single phase condition exists for temperature and pressure combinations that would place the system above the phase boundary line, with polymer dropping out of solution once the system conditions drop below the line. Consider the specific case of a CO2 flood in a reservoir at 180°F. and 4,000 psia, where the injector is at 130 ° F., and early gas breakthrough has taken place. The working of this process would require injecting a CO2 phase enriched with 7.1 vol.% toluene and 600,000 cst polymer as a one phase system at the injector. As this mixture moves through the reservoir and increases in temperature, the stability decreases, and once the temperature at fixed pressure crosses the phase boundary line, the polymer phase separates out to plug the zone.
Cost-Effective Methods of Profile Control in Mature Waterflood Injectors
Authors: Lerma M. K. , Giuliani M. A.
Published: December 2007

Injector profile control tends to be a challenge in any waterflood, but control problems are exacerbated in a multi-layered, heterogenous reservoir like those found in the L.A. Basin. This paper discusses the various methods of profile control used in two L.A. Basin fields; details of the methods used and the results achieved are included.
Why Water Soluble Corrosion Inhibitors Should be the Preferred Choice for Continuous Applications
Authors: Woollam R. C. , Merrett S. J.
Published: December 2007

Over recent years the Petroleum industry and its chemical suppliers have spent many millions of dollars searching for ever improving corrosion inhibitors for crude oil transport lines. During this time many different notations for a chemical's characterization have arisen, water soluble, oil soluble, oil soluble/water dispersible etc.

This paper argues, theoretically, that to achieve adequate protection of pipelines from continuous corrosion inhibitor addition the deployed corrosion inhibitor should be preferentially water soluble. It shows how the concentration of a product in the water phase can vary dramatically with both solubility and water cut. In addition, two other important parameters, dissociation and adsorption, are also discussed and shown to have a significant impact on product performance.