bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Rheology Model and Hydraulics Analysis for Tomorrow&s Wellbore Fluid Applications
Authors: Becker T. E. , Morgan R. G. , Chin W. C. , Griffith J. E.
Published: December 2007

Wellbore fluid applications continue to expand in complexity, necessitating more versatile rheological and hydraulics models amenable to efficient real-time data analysis. Substantial recent advancements have been made by numerous workers, applying the Herschel-Bulkley model to drilling fluids, highlighting the underlying importance of fluid rheology. However, this classic model alone does not fully describe the complexity of oilfield fluids. Therefore, this paper presents a Generalized Herschel-Bulkley (GHB) rheological model and hydraulic analytical method that accommodate a broader spectrum of wellbore fluids, whether of simple character, or having the complex properties of multiphase fluids such as foamed cement and high-density cements in addition to drilling fluids.

The GHB model offers several advantages: (1) it readily reduces to several popular conventional models (Newtonian, power-law, Bingham-plastic, Casson, and Herschel-Bulkley), (2) it can provide additional flexibility for characterizing apparent viscosity functions of current and future multiphase fluid systems such as lightweight cements, foams, and high-density slurries, and (3) it can provide an effective generalized framework for developing friction prediction equations. A highly accurate numerical simulator for the comprehensive family of fluids modeled by the GHB model was developed for predicting laminar flow-friction loss in pipes and annuli. The computational method, based on several exact integrals of motion, could be made as accurate as desired by decreasing mesh size. While the simulator itself is not ideal for real-time application, the results of comprehensive calculations using it were incorporated into field-usable software by developing "generalized explicit functions" that encapsulated all the physics correctly. These practical functions are in turn used for accurately and rapidly predicting friction loss of the GHB family of fluids in pipes and annuli (concentric and eccentric) for laminar, transitional, and turbulent flow.
The Role of X-Ray Computed Tomography in Core Analysis
Authors: Withjack E. M. , Devier C. , Michael G.
Published: December 2007

Over the past several decades, x-ray computed tomography (CT) has gained acceptance as a routine core analysis tool. Its use for in-situ saturation determination, for example, has made it the method of choice for steady state relative permeability testing. The main objective of this paper is to provide a repository of information on CT scanning for core analysis, and to group the many earlier studies into reservoir engineering categories for convenient reference by others in the future. The review is prefaced with the introduction of a conceptual model (Cloud Model) for representing the influences of major factors on reservoir NPV, and a discussion of the value of CT for core analysis. The literature review is followed by an update of emerging CT technology (microscanning), and presentation of a new method for 3-phase saturation determination using combined CT and NMR.
Matrix Acidizing Case Studies for the Point Arguello Field
Authors: Patton Bartley J. , Pitts Farrell , Goeres Tom , Hertfelder Gary
Published: December 2007

Several techniques and acid systems have been used to increase the productivity of the Monterey Formation, Offshore California. Reservoir production data will be used to evaluate the effectiveness of different acidizing techniques and systems used to treat the Point Arguello field. Basic acidizing physics will be covered to help explain the decision making process used to develop acid systems for the Point Arguello field. Acid systems will be tied back to their delivery method; coiled tubing, bull heading, foam diversion and perf washing to determine overall effectiveness of the matrix treatment.
Prediction of Flow Units and Permeability Using Artificial Neural Networks
Authors: Aminian K. , Ameri S. , Oyerokun A. , Thomas B.
Published: December 2007

An accurate description of the reservoir is necessary for predicting the reservoir performance. The flow unit model is most practical approach for reservoir simulation purposes. The flow units are defined according to geological and petrophysical properties that influence the flow of fluids in the reservoir. Identification of flow units requires permeability data. Predicting permeability distribution is a difficult problem in heterogeneous reservoirs due to insufficient permeability measurements. The geophysical well logs are the most abundant source of data in a reservoir. Therefore, a well log-based methodology for predicting permeability can enhance prediction of the flow unit distribution.

In this study, in a complex reservoir was successfully characterized using flow unit modeling. Statistical techniques were employed to identify flow units based on limited data obtained from core analysis supplemented by mini-permeameter measurements and geological interpretations. Permeability was then predicted from geophysical well log and preliminary flow units using artificial neural network (ANN). An innovative approach for training and testing of the ANN was developed which provided consistent and reliable predictions. The neural network predictions were then verified for the wells with core data. Well log data, available on substantial number of wells in the reservoir, were then utilized to predict the distribution of flow units, permeability, and porosity in the reservoir. This approach led to development of a reliable reservoir model. The accuracy of model was verified by successful simulation of the production performance. The methodology presented in this paper can serve as a new guideline for the characterization of reservoirs with limited core data.
Development of Heather Field Satellites, Northern North Sea, UKCS
Authors: Scott G. G. , Morel E. H. , Salter T. M.
Published: December 2007

As the Heather oilfield celebrates 25 years production, and comes to the end of its own economic life, development of the West Heather and North Terrace satellites will revitalise production from the area, and prolong the use of Heather platform for another ten years.

The West Heather and North Terrace oil accumulations were discovered and appraised in the late 1970s, at a time when the then Heather partners were endeavouring to find additional oil to supplement the disappointing production from the Heather field. The results of this drilling were not sufficiently promising to warrant further investment, and after 1987 no further drilling by the original field owners was undertaken.

A change of Operatorship in 1997, and acquisition of new 3-D seismic data led to further exploration and appraisal drilling in the West Heather area, and significant oil volumes in better quality reservoir has been discovered. The new accumulation is being developed as a subsea satellite, tied back to the Heather platform via a 7 km flowline system. It is planned to bring on the neighbouring North Terrace oil accumulation via this subsea system as part of a phased development.

This paper describes the West Heather development and the main factors that have led to bringing it to the point of sanction. These have been the attraction of Upper Jurassic exploration plays, the recognition of upside Brent reservoir potential in the area, investment by new Partners with an innovative business model for managing technical and financial risk, and the incentive of deferring Heather decommissioning.
Description of a Highly complex Reservoir Using Single Sensor Seismic Acquisition
Authors: McHugo S. , Cooke A. , Pickering S.
Published: December 2007

Sandstone injectite reservoirs have been found in recent years to be a significant source of reserves in the North Sea. However, the fields in which these reservoirs exist were often found relatively late in the exploration history of the basin and all too often by serendipity in the search for deeper reservoir objectives. The reason for this lies in the difficulty in seismically imaging this type of reservoir. In this paper we describe how seismic data from point-receiver seismic acquisition and the resulting pre-stack inversion of the data, were used in an attempt to predict the lithology, and visualize the morphology of a complex sandstone injectite reservoir in a North Sea oil field.
Transient Pressure Behavior of Dual Lateral Wells
Authors: Fahem Abdelhafid , Tiab Djebbar , Jokhio Sarfraz , Owayed Jalal
Published: December 2007

This paper presents an analysis method of the transient pressure behavior of dual lateral wells. Conventionally lateral wells have been analyzed using horizontal well analysis techniques. As we will show in this paper, that if the phase angle between the two lateral sections differ from p, they can not be treated as horizontal well and such practices any result erroneous reservoir properties. An infinite conductivity solution for dual lateral wells was developed by coupling both; the infinite conductivity horizontal well model and the superposition concepts.

From the sensitivity analysis study, it was found that infinite conductivity solution for dual lateral wells is affected by the horizontal anisotropy, phasing of the lateral sections, dimensionless horizontal separation, mechanical skin, wellbore storage. It is less affected by the dimensionless vertical separation and the contrast between the dimensionless lateral lengths. Transient pressure behavior of dual lateral wells appears to be more pronounced in the cases: (a) for a phase angle decreasing, (b) for a horizontal separation decreasing, and (c) for a horizontal anisotropy increasing. The effect of the phase angle decreases while increasing the dimensionless lateral lengths and horizontal separation. The effect of the horizontal anisotropy on the pressure behavior is more pronounced for high phase angles. The wellbore storage dominated flow period tends to be more affected for small dimensionless lateral lengths, LD. The effect of unequal lateral lengths and vertical separation are pronounced only at early times. The intermediate time pseudoradial flow period displayed by dual lateral wells is more distinguishable from the wellbore responses in the cases of a large phase angle and a high value of the horizontal separation. It is worthwhile to note that the responses of dual lateral wells having a phase angle, β= π, may be viewed as an equivalent single horizontal well.

Also Tiab's Direct Synthesis (TDS) technique methodolgy for dual lateral wells has been developed, which adds to the analysis of such wells. Few examples are solved in a step-by-step manner, which demonstrate the use of the method developed.
Advanced Web Technologies Give Real-Time Capabilities To Enhance Production Operations and Reservoir Management
Authors: Richardson S. , Keron H. , Jatmiko W. , Booker J. , Osugo L. , Donachie J.
Published: December 2007

The traditional industry methods and processes used for managing production operations and optimising well performance highlight a significant gap in integrating daily production operations with reservoir management. The consequence can be a reactive production management process that results in deferred production or suboptimal asset performance. This case study illustrates how a real-time well surveillance service was successfully implemented in a mature North Sea oil field, resulting in a significant production performance improvement and increased flexibility and visibility in managing production from the asset.
Automated Reservoir Surveillance through Data Mining Software
Authors: de Jonge Gert , Stundner Michael , Zangl Georg
Published: December 2007

High frequency reservoir surveillance data become available in an increasing number of oil and gas fields.

Real-time data from both reservoir and surface facilities open the possibility to control and consequently optimize field production in real-time.

This real-time control would be a step forward to the industry's next goal - The Smart Field.

An integrated software and data approach is presented based on Data Mining methods1. In this paper, the "Automation Task" concept is discussed which allows automation of data processing, event detection and user notification. An Expert System interface enables the surveillance engineer to program the software in order to run on a 24/7 basis.

Time savings in routine reservoir surveillance and accelerated production through faster and better reservoir management decision were identified as premium goals.
Technology Transfer into the Offshore Oil and Gas Industry
Authors: Tanner R. K. , Boyce G. , Quarini J. , Head P. , Dick J.
Published: December 2007

Technology transfer from other industries can offer major benefits to the offshore oil and gas industry but requires encouragement. The technology developers are often unaware of potential applications offshore, and oil and gas operators and contractors need to be convinced of the benefits. ITF's Pioneer Programme is a good mechanism for stimulating technology transfer as it offers feasibility study funding for higher risk but exciting technologies. Four examples of Pioneer projects are presented that describe technology transfer from the water, food, automobile and medical industries.
Optimising Well Service Resource - A Systematic Approach to Performance Improvement
Authors: Durham Craig , Fraser Ian , Morris Colin
Published: December 2007

Well service activity in Shell's Northern Business Unit is outsourced to an integrated services contractor with targets set for HSE, quality, and cost management. Various key performance indicators are measured to provide the necessary focus for control and improvement. Historically this focus has been on operational time improvements and associated rig day-rate savings. However, approximately 25% of annual well services expenditure represents equipment rental charges and hence any efficiency improvement can have a major impact on budget performance. In 2001 a system was introduced to track and co-ordinate the movement of all rental equipment deployed offshore. By closely monitoring the status of all items from loadout to return, baseline efficiencies were established. Using Supply Chain Management techniques such as Just-in-Time shipping, opportunity scheduling and influencing sub-contractor pricing has lead to utilisation efficiency improving from 48% to 62% in 2002, equivalent to over £0.5 million of eliminated costs. As fields mature and well interventions represent a greater portion of operating expenditure, this type of saving could ultimately make the difference between extended field life and final abandonment.
The Sustainability Assessment Model (SAM): Measuring Sustainable Development Performance
Authors: Baxter Tom , Bebbington Jan , Cutteridge David , Harvey Gordon
Published: December 2007

Business has a fundamental role to play in delivering Sustainable Development - the process needed to achieve a sustainable society. Sustainable Development is becoming increasingly recognised as a critical issue for the oil and gas industry to address, and act upon. This paper outlines a practical tool (The Sustainability Assessment Model - SAM) which has been developed to analyse, compare and rank Sustainable Development performance.

The SAM assesses the social, environmental, economic, and resource usage impacts of a project over its full life cycle including product use. It also helps address the remediation and restoration options.

The SAM monetises all the impacts so that they can be compared on a like-for-like basis. This also allows the impacts to be combined into a single measure which reflects the overall Sustainable Development performance of a project. This paper will show how SAM has been used to assess the performance of several energy projects.

A project focus was initially adopted in the belief that greater control over impacts can be influenced and achieved at this level. However this paper will also show how the tool has been used to:

Aid specific design decisions such as concept selection Assess the overall holistic Sustainable Development performance of an industry sector.
The Role of Trust in Safety Culture
Authors: Burns Calvin
Published: December 2007

Since the Piper Alpha disaster, the oil and gas industry has taken steps to develop a more positive safety culture. Safety climate surveys have been used to provide a snapshot of the state of safety by measuring the workforce's explicit attitudes and perceptions about safety at a point in time. Organisational theorists have argued that climate is only a surface manifestation of culture and that culture manifests itself in deeper levels of unconscious assumptions. Psychologists have shown that an individual is able to hold different evaluations of the same object (a conscious, explicit attitude and an unconscious, implicit attitude) and that an individual's explicit and implicit attitudes to something do not have to be the same. This paper investigates the explicit and implicit attitudes held by the workforce at a UK gas plant about the trustworthiness of their workmates, supervisors and the plant leadership. A short questionnaire was used to measure explicit attitudes and implicit attitudes were measured using a computerised task. The main finding was that a different pattern of results emerged for explicit and implicit attitudes about trust. The paper concludes by proposing a model of dual attitudes about trust in safety culture.
The Use of Multilateral Technology to Arrest Production Decline in a West-Texas Gas Field
Authors: Owodunni Adeyinka , Travis Tim , Dunk Gary
Published: December 2007

ExxonMobil successfully drilled, completed, and produced the first selectively, high-pressure (rated for 8,000 psi) stimulated multilateral well in the world - the Arch Benge #1. This use of multilateral technology is part of an initiative to use step-out and fit-for-purpose technologies to arrest production decline in the Parks Field Unit, West Texas. The well was designed to produce gas and retrograde condensate from the upper and lower porosity lenses of a geologically constrained Devonian limestone.

The Arch Benge #1 well is a good example of how to use multilaterals as a fit-for-purpose technology to capture maximum reserves at minimal incremental cost. The well drilled a total 6,600-ft of Devonian formation that would have been otherwise impossible to fully access due to current lease line restrictions and field rules. The Arch Benge #1 was designed and implemented as a Technical Advancement for Multilaterals′ (TAML) level 2 dual-lateral well that successfully utilized a temporary, high-pressure TAML level 5 completion architecture for selective stimulation. This novel completion design and flexibility resulted in to significant cost savings and ensured the successful stimulation, test, and production of each lateral.

Other challenges included creating two separate lateral junctions within a 100-ft interval of geologically constrained Devonian limestone and isolating these lateral junctions during the high-pressure acid fracture treatments. Selective isolation was essential to test each lateral independently and maximize production from these tight carbonate reservoirs.

The Arch Benge #1 multilateral well is a good illustration of how to integrate proven and existing field practices with multilateral technology to achieve optimum value. The result is a 20% drilling cost savings over that of two separate wells. In this paper the multilateral selection process, planning, operational procedures, and result comparison with conventional wells will be discussed. The well is currently producing commingled gas and condensate from both laterals through a single string of tubing into a field gathering system.
An Assessment of Subsea Production Systems
Authors: Devegowda D. , Scott S. L.
Published: December 2007

The rapidly accelerating shift to subsea production systems represents a significant departure from conventional operations. Historically, subsea wells have had a good track record. However, complex subsea systems are now being deployed in ways rarely encountered in previous development schemes. These increasingly complex systems present a number of technical challenges. This paper presents an assessment of subsea production systems, considering the technical, operations and safety issues associated with this development modality.

This assessment considers the following general areas: 1) subsea processing; 2) flow assurance; 3) long-term well monitoring and, 4) safety & environmental concerns. A review of the state-of-the-art in each of these areas is presented and several technical and operational gaps are identified. One of the most striking findings is the low ultimate recovery anticipated from many subsea wells. Two new technologies that can have a positive impact on recoveries are subsea multiphase pumping and subsea separation/processing. This assessment found, however, that the safety systems seem to be absent from current subsea processing plans. Other concerns include the inability to monitor subsea wells for sustained casing pressure, a widespread problem in the GOM. With regard to flow assurance, much work has been done to develop design tools for flow assurance, little has been done in the area of monitoring subsea production systems to detect and locate these materials. As more subsea systems are placed in operation, the monitoring and operation needs (rather than the design needs) will likely emerge as the top priority.
Nonlinear Multivariate Optimization of Production Systems Using a Mechanistic Model
Authors: Del Río-H. J. , Camacho-V. R. , Robles A. , González-T. F. , Santamaría N.
Published: December 2007

This work presents results on the optimization of production systems performance for oil and gas reservoirs. Genetic and Polytope algorithms are used for the nonlinear optimization problem considering appropriate values of several variables like tubing string and wellhead choke diameters, separator pressure and surface pipeline diameter.

The model considers several components and different methods to evaluate the pressure drop in each component. The sensitivity of each component of the system can be evaluated. This model includes a mechanistic model to predict the pressure drop due to multiphase flow for any tubing angle with upward and downward flow. The method of splines is used to eliminate the presence of pressure gradient discontinuities in flow pattern boundaries. This property of the model allows us to use optimization algorithms in an efficient manner.

Several examples are presented to illustrate the methodology proposed in this work.
Ecosystem-Based Approaches to Offshore Oil and Gas Operation: An Alternative Environmental Management Technique
Authors: Khan Ibrahim M. , Islam M. Rafiqul
Published: December 2007

The oil and gas sector is one of the most lucrative sectors in business but reducing its environmental impact is one of the most pressing issues today. Practically all activities of hydrocarbons operations are accompanied by undesirable discharges of liquid, solid, and gaseous wastes, which have enormous impacts, especially in the marine environment. There is clearly a need to develop a management approach in oil and gas operations, which ensures minimization of adverse environmental impacts. Unfortunately, in trying to achieve this goal, the oil and gas industry has adopted some major misconceptions in it "environmentally correct" approaches, which are causing further damage to environment.

This presentation will address the present environmental misconceptions common in oil and gas development. Some innovative solutions are proposed to solve the problems caused by oil and gas development activities in the marine environment. These solutions are based on the holistic environmental approach, which takes into account the complexity of natural processes and which takes advantage of these processes, rather than working against them. Some of the proposed models are: marine protected area in oil sites (MPAOS), iron fertilization and CO2 utilization (IFCU), integrated coastal pollution balancing (ICPB), artificial recruitment in fisheries (ARFS), and artificial rigs from oil rigs (AROR). The main goal of the proposed approaches is to maintain and restore ecological sustainability and ecosystem integrity. As a result, each solution will not only stop destruction of the environment but also improve the productivity, biodiversity and fisheries in the marine ecosystem. The existing solutions to these problems involves focusing on the individual problems without integrating the total ecosystem, which might benefit one sector but is harmful to the whole ecosystem overall.

The proposed approaches can be applied to the marine environment, which environmentalists report is the most abused by the oil and gas sector. These approaches have great significance in utilizing oil and gas operations related pollution, fisheries improvement and ecosystem restoration.
Drilling High-Angle Wells in an Amazonia Natural Life Reserve
Authors: Casalis Daniel , Malfetana Omar , Fausto Jara
Published: December 2007

The Ishpingo-4 and Ishpingo-3 wells were drilled by Petroecuador—Ecuador's state-owned company—in the ITT (Ishpingo-Tiputini-Tambococha) field. This field is located in the Yasuní National Park in the Ecuadorian Amazon region, which was declared a World Biosphere Reserve by UNESCO in 1989.

The Ishpingo wells were drilled primarily to delineate oil reserves, and the project was managed by Petroecuador and PETROBRAS ENERGIA S.A. (PE) professionals. PE contributed recent experience gained from drilling two appraisal wells, Apaika 1x and Obe 1x, across the lease line. These wells were drilled and tested within the same natural life reserve area with similar heliborne equipment, materials and personnel.

To operate in this highly sensitive area, PE and Petroecuador developed a specific Environmental Management Program (EMP) that actively involved environmental authorities and representatives from native communities. The EMP was prepared using the PE Integrated HSE Management System certified by ISO 14001 and OHSAS 18001. To assess the results, audits were jointly conducted by the Ecuadorian government, the native communities and the company.

In 1992, two vertical wells—Ishpingo-1 and Ishpingo-2— were drilled in the Ishpingo field. The additional appraisal wells were planned with extended reach trajectories from existing well locations to minimize environmental impact. The logistics, drilling and testing of the two high-angle wells were operationally successful, and the geological target was reached to confirm hydrocarbon occurrence and reserve size. Ishpingo-3 set records in Ecuador as the steepest dip well drilled in a 16-in. section and the steepest dip well out of all high-angle wells drilled in that country.

The high-viscosity crude oil—12° API—as well as the high-deviation angle of the wells prevented the use of conventional testing techniques. Therefore, special methods, together with state-of-the-art directional equipment, were employed to determine both deliverability and reservoir boundaries. The effective application of these technologies, with optimum allocation of the resources and good terrestrial-fluvial-aerial logistics, resulted in a highly successful operation overall.
Development and Installation of an Inline Deliquidiser
Authors: Chin R. W. , Stanbridge D. I , Schook R.
Published: December 2007

Cyclonic separation technology, over the past few years, has received increasing attention because of weight and space savings for topsides and subsea applications. In addition to new builds, the cyclonic technology plays a major role in debottlenecking and upgrading. This paper will present the development and installation of an inline cyclonic deliquidiser.

The inline deliquidiser is new technology that has been developed and qualified with a major oil company and in mid 2002, was installed on one of their platforms in the North Sea. The need for such a device arose because high liquid loading of a scrubber was causing carryover to the downstream equipment. With little space, if any, to implement solutions as well as a desire to minimize downtime, an inline cyclonic separator in addition to scrubber modifications was deemed the best solution. During laboratory tests, and now offshore tests, the inline deliquidiser was shown to knock out 90-95%+ of the liquid upstream of the vessel. Design, laboratory tests, and field results will be presented. Potential applications of the inline deliquidiser will also be given.
Rediscovering Non-Darcy Flow Effect In Gas Reservoir
Authors: Armenta M. , Wojtanowicz A. K.
Published: December 2007

The paper demonstrates and explains the importance of global inclusion (i.e. throughout the reservoir) of Non-Darcy (N-D) flow component for better prediction of well performance in gas reservoirs with bottom water drive by using a numerical simulator. Traditionally, Non-Darcy flow effect in gas reservoirs has been attributed only to high gas flow rates, and considered locally around the wellbore. Consequently, most numerical simulators have the N-D component assigned to the well rather than distributed throughout the reservoir. Also, the common judgment is that the effect is insignificant at gas rates lower than 10 MMscf/d, so it would not affect gas recovery in the low-rate wells.

In this project, we used an analytical model, field data, and a numerical simulator with global and local N-D component to study sensitivity of final recovery and gas rate to N-D flow for a variety of reservoir properties. The results show that disregarding the N-D flow globally leads to overestimation of cumulative gas recovery by up to 42.2 percent. Moreover, this overestimated recovery is the same when N-D is ignored, or assigned locally to the wellbore.

It is also shown that N-D effect is significant at low production rates. Shown is the range of reservoir properties where gas wells producing only 9.8 MMscf/D would have total pressure draw-down comprising 70% contribution of N-D flow effect.
Analysis and Interpretation of Gas Diffusion in Quiescent Reservoir, Drilling, and Completion Fluids: Equilibrium vs. Non-equilibrium Models
Authors: Faruk Civan , Rasmussen Maurice L.
Published: December 2007

This paper presents physically and mathematically rigorous transient-state equilibrium and non-equilibrium diffusion models for practical determination of the gas diffusion coefficient from experimental measurements of the gas pressure decline in a closed tank by dissolution of gas in a quiescent liquid (oil, brine, drilling mud, and completion fluids).

The short- and long-time solutions of this model for equilibrium and nonequilibrium transfer processes are developed analytically. These solutions are reformulated to enable direct determination of the best estimate of the diffusion coefficient by regression of the resultant analytical expressions to experimental data. These analytic expressions are used to establish the significance of the equilibrium vs. nonequilibrium gas dissolution in liquids under in situ conditions. The experimental data given in previous studies are analyzed by means of the present improved methods and the diffusion coefficients obtained are compared with the reported values.

The results developed in this paper can be utilized for determination of the gas diffusivity, the interface mass-transfer coefficient, and the rate of dissolution of the injection gases in oil during secondary recovery, and the rate of dissolution and separation of light gases in reservoir oil and brine, drilling mud, and completion fluids.
Compositional Simulation of WAG Processes for a Viscous Oil
Authors: Li Dacun , Kumar Kamlesh , Mohanty Kishore K.
Published: December 2007

The goal of this work is to develop a compositional model for WAG injection in a medium-viscosity oil, low-temperature reservoir like Schrader Bluff Pool in the Milne Point Unit, Alaska. Compositional simulation of WAG displacement with CO2-NGL and Prudhoe Bay gas-NGL mixtures shows that three-hydrocarbon phases form in situ because of low temperature. A four-phase relative permeability formulation has been developed by considering the mixed-wettability of the formation and the saturation paths. The simulation results are compared with the laboratory experimental results from the literature. The sensitivity of the laboratory-scale oil recovery to relative permeability, pressure and solvent composition is studied. The sensitivity of oil recovery in a 2D quarter five-spot pattern to relative permeability, WAG ratio, slug size is also studied. CO2 – NGL mixture is a very effective solvent for this reservoir. The minimum miscibility enrichment is more sensitive to pressure for Prudhoe Bay gas – NGL mixtures than in the case of CO2 – NGL mixtures. The oil production rate is sensitive to relative permeability formulation. Oil recovery is faster at lower WAG ratio and higher slug size.
Detection and Reuse of the Produced Chemicals in Alkaline-Surfactant-Polymer Floods
Authors: Wang Wei , Gu Yongan
Published: December 2007

Alkaline-Surfactant-Polymer (ASP) flood processes have been increasingly applied in the oil fields due to their high ultimate oil recovery. However, a major technical challenge is how to significantly reduce the amount and the cost of chemicals used such that ASP floods can become cost-effective as well. On the other hand, field applications show that the concentrations of alkali, surfactant and polymer remain relatively high in the produced fluids of ASP floods. Thus, successful detection and reuse of these chemicals can substantially reduce the capital cost and the environmental impact. In this paper, several methods are applied to detect each chemical and quantify its concentration in the produced fluids. Also re-injection of the produced chemicals is conducted for further enhancing oil recovery. More specifically, first, the total interactions of each chemical with the oil-brine-rock system are studied. With the developed detection techniques for each individual chemical used in ASP floods, the total loss of each chemical is measured. The chemical loss is caused by its chemical reactions with the crude oil and the reservoir brine, as well as its adsorption onto the rock surface. Secondly, coreflood tests are performed for alkaline floods, surfactant floods, alkaline-surfactant (AS) floods, and ASP floods to determine their respective tertiary oil recovery. Hence, a better understanding of how each chemical contributes to enhanced oil recovery (EOR) is achieved. Thirdly, typical chemical concentrations in the produced fluids are measured and compared with those in the injected slugs so as to determine the potential of reusing these chemicals in practice. The follow-up coreflood tests of reusing these produced chemicals are carried out by directly re-injecting the produced fluids. The test results show that the produced chemicals can still effectively enhance oil recovery by up to 19.7%. It is anticipated that the detection and reuse techniques studied in this work should facilitate the design, optimization and implementation of ASP flood projects.
WAG Pilot Design and Observation Well Data Analysis for Hassi Berkine South Field
Authors: Lo L. L. , McGregor D. S. , Wang P. , Boucedra S. , Bakhoukhe C.
Published: December 2007

The Hassi Berkine South field (HBNS) is an undersaturated, low-viscosity, moderate permeability oil field within the center of the Berkine Basin in Algeria (Fig. 1). Discovered in January 1995, the HBNS field had first oil production in 1998 from the Trias Argilo-Greseux Inferieur (TAGI) reservoir with a reservoir development plan (RDP) of crestal, miscible gas injection and peripheral waterflood. Full-field WAG, as a secondary recovery process, is currently under investigation for the potential increased oil recovery and higher oil rate. This paper describes the design of the miscible water alternating gas (MWAG) pilot test and presents novel techniques for correcting observation well log data to reflect the miscible displacement process.

A simulator sector model for the pilot area was used to design the MW AG pilot parameters (e.g., solvent/water volume, WAG ratio, timing). Next, measurements from the first WAG cycle were used to calibrate key parameters in the sector model, and to define WAG parameters for subsequent cycles.

For the initial pilot design analysis, the fine areal gridding and vertical layering were taken from the Prudhoe Bay pilot simulation experience1,2. The objective of the pilot design is to collect optimal data from the observation well in the shortest possible time. The initial simulation work defined solvent injection rates, slug sizes, cycle lengths, and WAG ratios to achieve these goals.

Subsequently, reservoir calibration with surveillance measurements from the first WAG cycle allowed for fine-tuning of key MWAG parameters. This work required correcting hydrocarbon saturations from the surveillance tools to be representative of the miscible displacement process. A method has been developed to correct log-derived immiscible saturations to reflect the miscible process occurring in the reservoir and simulated in the sector model.
A Quick Method to Determine Permeability-Anisotropy Orientation from interference Testing
Authors: Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

This study provides a quick method to estimate the orientations of permeability/flow anisotropy from pressure interference responses only. The method can identify a 90-degree range of the anisotropy orientation from two observation-well responses and a range approximately 45-degree (or less under favorable conditions) from three observation-well responses. Formal analysis (such as type-curve or simulation matching) and information of reservoir-fluid properties are not required.

Significances of the developed method are: (1) It provides solution bound that contains the unique solution (if exists). (2) It may be the only solution obtainable if the adopted formal method (such as Papadopulos-Ramey procedure) fails (which is not known a priori). (3) It provides the most desirable information, namely, the anisotropy orientation, from a timeconsuming and expensive (e.g., lost production) interference test. (4) It can be implemented for two observation wells.

The validity of the developed method is demonstrated by one ideal and two field examples. We strongly recommend the developed method as part of "diagnosis" prior to any formal interference-testing analysis.
Successful Well Testing Operations in High-Pressure/High-Temperature Environment: Case Histories
Authors: Boscan Jorge , Almanza Edgar , Wendler Curtis
Published: December 2007

In the oilfield, high pressure/high temperature wells (HP/HT) are those with more than 10,000 psi bottomhole pressure and bottomhole temperatures in excess of 300° F. As such, the severe reservoir environment in these wells requires special testing equipment that can sustain the high pressures and temperatures. Special testing processes and equipment have been designed to reduce the risks in achieving successful evaluations, and HP/HT wells can be successfully tested under both rig-supported and rigless operations and in both cased- and openhole conditions. This paper will compare some of the testing experiences in HP/HT wells tested several years ago, and some that are more recent and have used new technologies to increase the success in obtaining the information needed for the evaluations.

With the new technology, it has been possible to transmit the data collected during the evaluation to offsite locations using internet capabilities, collect more accurate data using memory gauge systems capable of working at high temperatures, gather downhole real time data using various collection tools, improve well productivity by applying propellant technologies, and improve perforating performance by using state-of-the-art charges.

The paper will describe the downhole tool system used to perform the well testing evaluation under severe well conditions. Also discussed will be how it was capable of acquiring well data in real time, and then, disseminating it over the Internet to allow collaboration with a larger number of individuals. This allowed immediate decisions concerning operational or program changes to be made and implemented at the wellsite.

The system has been successfully deployed on a number of well tests in Australia and Venezuela, and the paper will present some of these case histories as illustrations of the well testing capabilities now possible in varying conditions
Sandstone Acidizing Treatment of a Horizontal Openhole Completion Using Coiled Tubing from a Deepwater Floating Production Platform
Authors: Hardin F. Lee , Barry Mike D. , Shuchart Chris E. , Gdanski Rick D. , Ritter D. Wes , Huynh David V.
Published: December 2007

A sandstone acidizing treatment was performed on a 1550-ft horizontal open-hole gravel packed completion to restore productivity following impairment by fines migration. Extensive pre-job laboratory testing was conducted to identify the optimum treatment recipe. The treatment was placed utilizing coiled tubing on a floating production platform and pumped from a marine stimulation vessel. Pre- and post-job production logs were run to verify treatment effectiveness. This paper focuses on the problem identification, treatment design, and measurement of results.
Downhole Permanent Monitoring Tackles Problematic Electrical Submersible Pumping Wells
Authors: Macary S. , Mohamed I. , Rashad R. , El-Noby M. , A/Latif M. , Awni I. , A/Khalek M.
Published: December 2007

Permanent monitoring of downhole equipment and production in artificial lift wells is an excellent method of diagnosing conditions and determining the appropriate approach to avoid loss of production or of the well.

Belayim Petroleum Company in Egypt (Petrobel) has used permanent monitoring sensors since 1994. The systematic data are used by the reservoir and production engineering staff to tackle problems such as high failure rate, sand fill-up, scale, ESP wear, and electric failures.

Petrobel currently has twenty downhole gauges, and 8 other systems are waiting associated accessories before installation. Each permanent gauge sends nine measurements per minute to the surface in real time yielding an incredible volume of information.

Downhole gauges supply accurate information about the reservoir, downhole, and the pumping system. This knowledge, in turn, is used to increase the run life of the artificial lift system through optimization of the reservoir pressure and artificial lift system performance.

This paper demonstrates the long-term benefits of using subsurface permanent gauges to complement artificial lift equipment and provide real-time data to optimize well and/or field production. Case studies illustrate both offshore and onshore problems. Examples are given of wells that have been converted into successful artificial lift completions through proper interpretation of the gauge measurements and use of the information to optimize production. This paper brings data interpretation to a new level of prediction, which enhances economics and minimizes risk in production operations, especially offshore.
A Modern Approach to the Optimum Design of Sucker-Rod Pumping System
Authors: Firu L. S. , Chelu T. , Militaru-Petre C.
Published: December 2007

This paper presents an improve optimization criterion that permit to select the optimum pumping mode from a large number of combinations of pumping rod parameters. The function that modeling the optimization criterion represent the sum of non-dimensional pumping rod parameters. The optimization criterion developed, includes eight operational parameters that characterizes the sucker-rod pumping system: (1) the maximum polished-rod load, (2) the maximum polished-rod stress, (3) the safety coefficient at variable loads, (4) the asymmetry coefficient, (5) the stroke efficiency, (6) the volumetric efficiency, (7) the buckling length of the sucker-rod string and (8) the performance index. Each of these parameters can influence the efficiency of the pumping system.

In order to select the optimum pumping mode, calculations must be made covering a wide range of variables. If four rod sizes are selecting with the available polished rod stroke lengths, pumping speeds (from 3 to maximum SPM of the pumping unit) and six plunger diameters, there are approximate 2200 possible pumping modes that may be considered. The optimization criterion proposed permit to select (using the computer program) only one pumping mode considered the best that correspond with maximum efficiency. The design technique used, allows prediction of surface dynamometer card using the exact kinematics parameters of pumping units, static loads, fluid friction along the string and dynamic rod loads, and the downhole cards based on solutions of the wave equation. Also, the main pumping rod parameters and the length of rods in compression are calculated. The result of this work is a complex computer program based on improve optimization criterion and pumping system design calculations. The application of this criterion for many suckers pumping wells, increases the efficiency of pumping system.
Safety Critical Systems Principles Applied to Drilling Engineering and Well Services Software
Authors: Sawaryn S. J. , Sanstrom B. , Williamson H. , Kirkman M. , McColpin G.
Published: December 2007

Drilling and Well Services software such as casing design, directional collision avoidance scans and well control applications were introduced as Safety Critical Systems in the paper SPE 73893. A serious, undetected failure in the development or use of one of these products could result in loss of life or catastrophic environmental damage. It was concluded that safety-critical software should only be used within the strict confines of a controlled management system, where software integrity, change, data, process and people competency are all tightly managed. Audits were used to identify best practice and areas for improvement.

The paper describes aspects of the controlled management environment developed over the last 18 months in response to the audit's recommendations. The first step was to introduce a series of principles covering software development, implementation, fault tracking and use. These principles are now incorporated as standards, supporting the BP Wells Policy. Both safety and business critical components are now formally incorporated in the vendor's, Landmark Graphics development process. Major reviews involving other operators have been conducted on the casing design and well control applications. A complete listing of the principles is provided in the paper. Their application is illustrated using examples from the casing design, well control, pore pressure, fracture gradient and directional applications. Simple procedures used to track both progress and adherence to the principles are also presented.