bluuebunny/crossref_metadata_2025 huggingface dataset:
Quantifying the Impact of Structural Uncertainties on Gross-Rock Volume Estimates
Authors: Samson P. , Dubrule O. , Euler N.
Published: December 2007

It is a common experience among geoscientists that structural uncertainties are crucial, especially when development decisions have to be taken on the basis of a small number of wells and a 3D seismic interpretation. Changes in the approach used for time-to- depth conversion and, to a lesser degree for horizon picking, may significantly impact the value of the Gross-Rock Volume (GRV). The methods presented here assume that maps of uncertainty on the time pick and on the average velocity have been produced, and they solve the problem of evaluating the impact of these uncertainty maps on GRV uncertainties.

The methods proposed consist of generating "possible" error maps that are all within the range provided by uncertainty maps. A "possible" depth map is obtained by adding an error map to the reference case. A simulated GRV can then be computed between the simulated top of the reservoir, the base of the reservoir (deduced by adding a thickness map to the simulated top, a thickness uncertainty may have been accounted for) and the Hydrocarbon-Water Contact (HWC) (its depth may have been simulated). By iterating many times (several hundreds) histograms and expectation curves of the GRV can be derived.

Introduction

The industry shows a growing interest for managing seismic uncertainties in a reservoir as they can dramatically impact the Gross-Rock Volume (GRV) estimates, especially when dealing with gently dipping structures at field appraisal stage.

Methods to simulate errors are presented as well as the use of resulting error maps (depth or time and velocity error maps) to generate "possible" depth maps. These "possible" depth maps can then be used to compute the simulated GRV. These methods are fast, and can be used to generate a great number of realisations (several hundreds) in a few hours on a workstation. Such an approach allows statistical analysis using histograms and expectation curves to derive key values such as 15%, 50% (median) and 85% quantiles.
Economic Optimization Of Liquid CO2 Fracturing
Authors: Luk Samuel , Apshkrum Mark
Published: December 2007

The use of liquid CO2 as a fracturing fluid has proven to be an effective stimulation for the increased production of gas in Canada and the United States. The process involves the injection of 100% liquid CO, as a proppant carrier to create a fracture and form a highly conductive channel from the wellbore into the reservoir.

The process has recently been optimized with the addition of nitrogen gas. Overall treatment costs were reduced by volumetrically replacing the more expensive liquid CO2 with gaseous nitrogen. Additional cost savings were realized with decreased power requirements due to lower liquid pumping rates and reduced friction pressures.

The results of more than seventy treatments utilizing N2/CO2 fracturing operations have been used to evaluate the limitations of this new development. The use of downhole pressure and temperature instrumentations has aided in the development of a computer simulator which evaluates the economic benefits of adding nitrogen to 100% liquid CO2. This paper will describe the computer simulator and discuss the variables in optimizing the new commingled N2/CO2 fracturing stimulation.
Coalbed Methane/Fuel Cell Operation for Direct Electric Power Generation
Authors: Haskew Tim A. , Haynes Charles D , Boyer CM , Lasseter E. L.
Published: December 2007

Methane released to the atmosphere during underground coal mining operations is a greenhouse gas and wastes a valuable enery resource. Coal mining in the United States released an estimated 190 to 300 billion cubic feet (Bcf) of methane into the atmosphere in 1990. Based on the current trend of increasing coal production and the mining of deeper, methane-rich coal deposits, methane emissions from coal mines have been forecast to be 260 to 450 Bcf by 2010. Because of inadequate methane capture technology, less than 5 percent of methane released during coal mining is currently recovered for use. New initiatives for coalbed methane will increase its recovery, thus providing important environmental and safety benefits while enhancing the worldwide natural gas supply. This investigation determined the feasibility for installing a 200 kW phosphoric acid fuel cell at a large underground coal mine located in the Black Warrior Basin of Alabama. Assurance of supply, variation of coalbed methane quality, and economic feasibility were studied. The fuel cell can be operated directly from variable-quality coalbed methane produced from underground mining. Waste heat from the fuel cell can be used in the mine's coal dryer, allowing a portion of the coal normally consumed in the dryer to be sold. Excess electric power, if available, can be sold to the public utility grid. An energy cost of approximately SO.05/kWh is necessary for the direct generation of electric power from a coalbed methane/fuel cell system to be competitive.
The Use of Slimhole Drilling and Monobore Completions To Reduce Development Costs at the Kuparuk River Field
Authors: Pearson C. Mark , Petrash Denise K. , Zernell Jim T. , Zanghi Mike
Published: December 2007

SPE Members

In 1994, a low cost development and operating plan for future wells at the Kuparuk River Field was proposed with the goal of reducing well costs 30% by the end of 1996. This paper presents this plan of a slimhole drilling and monobore completion program, a discussion of the critical issues addressed to successfully make the change, and field results from the first 16 wells drilled in 1994 and 1995.

A review of historical cost information is included which covers drilling and completing wells using the conventional well designs that had become standard in the field for the previous ten years. A variety of new slimhole well plans are presented for both production and injection wells together with a discussion of their potential application and cost savings. The paper concludes with a look at future work plans and opportunities for additional cost savings through the use of slimhole wells.

Introduction

Located in the Alaskan Arctic, the Kuparuk River Field is one of the United State's largest producing oil fields (300,000 barrels oil per day), and covers an area of approximately 115,000 acres. The field was discovered in 1969, but was not economic for development until 1977, after completion of the Trans-Alaska Pipeline. Figure 1 shows the field location on the North Slope of Alaska. Field development was started in 1979 using gravel pads as central drill sites from which deviated wells are drilled to drain a four section area (4 square miles). Initial development is on 160 acre well spacing with some 80 acre infill locations.

The Kuparuk reservoir is a sandstone at approximately 6000 feet subsea with solution gas drive as the primary production mechanism. The majority of the field is under secondary recovery receiving pressure support through a combination of waterflood and water alternating immiscible and miscible gas injection. Previous reports have documented both the geological description and the reservoir mechanisms of the field.

Production occurs from two horizons within the Kuparuk sandstone. An upper sandstone interval, referred to as the C Sand, is present over most of the southern half of the field and consists of very coarse to very fine grained siderite and sandstone. With average permeabilities of 130 md to 2600 md, and net pay ranges up to 80 ft, the C Sand typically produces at rates from 1000 to 5000 barrels per day (BPD).

The A Sand, the lower producing zone, is present throughout the field and contains 65% of recoverable oil in place.

P. 145
A Field Trial to Test Fiber Optic Sensors for Downhole Temperature and Pressure Measurements, West Coalinga Field, California
Authors: Karaman Osama S. , Kutlik Roy L. , Kluth Ed L.
Published: December 2007

A field trial to test fiber optic sensors for temperature and pressure measurements was completed in two temperature observation wells in a steamflood area of the West Coalinga Field in Coalinga, California. Objectives of the trial were to test a novel hydraulic deployment system that can easily install and retrieve fiber optic sensors from wellbores and to test the data quality from a fiber optic Distributed Temperature Sensor (DTS) and a pressure sensor.

Deployment of the temperature and pressure fiber optic sensors was successfully demonstrated by using the hydraulic deployment technique. Excellent data correlation was obtained between the DTS and the conventional wireline conveyed temperature survey tools. Similarly, the pressure sensor showed impressive resolution and dynamic response capabilities. Since the fiber optic system has the capability of providing continuous reservoir temperature and pressure data, reservoir management in primary or assisted recovery projects can be improved.

Introduction

The objectives of this field trial were threefold:first test a hydraulic deployment system whereby a thin fiber optic cable can be deployed and retrieved easily.test a Distributed Temperature Sensor (DTS) for data quality and reliability of obtaining temperature profiles in a high temperature environment.test a fiber optic pressure sensor in a high temperature environment.

The pressure sensor, which was simultaneously deployed with the temperature sensor in a closed system, was tested by applying pressure from the surface. The performance of both systems proved very effective and provided high quality data in a high temperature environment.

The field trial took place in the West Coalinga Field. The Field is located on the west side of the San Joaquin Valley approximately 100 miles northwest of Bakersfield, California. Field production is primarily heavy crude (12 to 15 API) from the Miocene Temblor Formation. The target reservoir consists of two sand layers separated by a shaly layer. The sands are unconsolidated with an average porosity in excess of 30%, an original oil saturation ranging from 45% to 55%, and an average air permeability of approximately 800 millidarcies horizontally. The upper sand layer averages 45 ft. in thickness, while the lower sand is about 35 ft. thick.

Steam injection in this reservoir was initiated in October 1988 and is ongoing today. Production from the constituent reservoir sand layers is enhanced by steam injection through a single tubing string. Permeability variations between the two sand layers resulted in uneven processing over major portions of the field. Since steam injection costs are the highest of all operating costs, it is critical to manage heat distribution in the reservoir properly.

P. 351
Improved Recovery of Light / Medium Heavy Oils in Heterogeneous Reservoirs Using Air Injection / Insitu Combustion (ISC)
Authors: Greaves M. , Wilson A. , Al-Honi M. , Lockett A.D.
Published: December 2007

Improved Recovery of Light / Medium Heavy Oils in Heterogeneous Reservoirs Using Air Injection / Insitu Combustion (ISC).

A one-quarter of a 5-spot physical model was used to carry out a series of low pressure air injection / insitu combustion (ISC) tests on light and medium heavy crude oils, to investigate the effect of reservoir heterogeneity on oil recovery.

It was found that a horizontal producer well does not act as a high permeability streak, but actually increases and brings forward production.

Extensive work on the construction and saturation of an artificial consolidated porous media was successfully undertaken and is now ready for further combustion experiments.

Introduction.

The demand for oil world-wide is rising at about 1-2% a year. This, combined with the increasing difficulty of finding new large reservoirs has put pressure on major consuming countries, especially in mature field areas such as N. America and the UK Continental Shelf (North Sea), to develop new recovery techniques, i.e. improved oil recovery (IOR) - Gregory, 1995.

When the reservoir energy is great enough (initially), the oil will normally flow to the producing well and up to the surface without any additional pumping. This is called primary recovery.

When the natural energy becomes too low the well needs to be pumped or injected with water or gas to displace more oil. The latter is called secondary recovery.

Waterflood is a secondary recovery method and is used extensively to increase recovery up to 50% of the original oil in place (OOIP).

Oil is left in a reservoir after waterflooding for two principal reasons: -Some oil remains in parts of the reservoir that have not been adequately swept by water. This inefficient sweep can be caused by viscous fingering, - Peters et al, 1987, (pronounced in both light and heavy oil reservoirs), but also by adverse heterogeneity and channelling effects in the reservoir. Significant oil, at high saturations, may also be trapped beneath shale layers, which are difficult to locate precisely.In the regions that have been frilly swept, oil is trapped in the form of droplets, or ganglia in the pores of the rock by capillary forces.

Clearly, with at least 50% of OOIP still remaining in the reservoir, increased attention needs to be focused on ways of increasing the recovery. Improved oil recovery techniques (IOR), especially enhanced oil recovery (EOR) processes such as air injection (low temperature oxidation and in-situ combustion - high temperature oxidation) need to be investigated.

The principle of insitu combustion is to burn part of the oil (or fuel fraction, i.e. coke), to mobilise the remaining oil. Combustion is started by an ignition device, or by spontaneous ignition, which raises the zone surrounding an injection well to a significantly high temperature, so that continued injection of air or oxygen containing gas causes the combustion to self propagate. P. 435
The Challenge of Developing and Enforcing a Goal-Setting Regulatory Regime
Authors: Todd Iain , Whewell Ian
Published: December 2007

This paper charts the development and implementation of the UK's goal-setting regulatory regime for health and safety in the offshore sector. It addresses both the benefits resulting from these changes, and the difficulties encountered, and looks forward to the consolidation of the regime over the next few years.
HSE Training and Competence Assessment in the Geophysical Industry
Authors: Covil M. W. , Soethout Joost A. , Reynolds Gerry , Carouso Mark , Jeffers Stuart
Published: December 2007

This paper looks at the efforts of the seismic geophysical industry to continually improve it's health, safety and environmental performance, and in particular to improve the HSE behaviour and understanding of individuals within the industry. Specifically it deals with Ihc HSE training and assessment of competence of individuals in relation to their job responsibilities, based on best industry practice
Human Factors in E & P Facility Design, a Participatory Approach
Authors: Dekker G. F. , van den Bergen E. A.
Published: December 2007

To ensure that ergonomics are taken into account in the conceptual design phases of engineering projects, NAM has introduced the "Ergonomics in design" workshop. This paper describes the general format, timing and techniques used in these workshops. An example of a case study is presented together with a cost benefit analysis. Finally, a concluding summary of the workshop success factors is given together with the areas for further improvement.
Environmental Assessment on Alaska's North Slope
Authors: Herlugson C. J. , Parnell J. A.
Published: December 2007

Since oil production began at Prudhoe Bay, Alaska, in 1977, numerous monitoring programs have examined the region’s biota in an effort to establish baseline conditions and support impact assessments. These programs are used to reduce or mitigate changes resulting from oil and gas development. North Slope exploration and production operations are governed by a complex set of regulations that often require monitoring. Monitoring programs are conducted annually to measure air emissions, water quality, and the distribution and abundance of wildlife within the operating areas.
Environment, Health & Safety Management Systems for Upstream Oil & Gas Projects in Developing Countries
Authors: Gossen R. G. , Mann G. J.
Published: December 2007

The international oil and gas exploration and production industry faces a vast array of environmental issues that are global in nature but play an increasingly prominent role in individual project decision making. When placed against a backdrop of socio-political and cultural challenges presented in developing countries, project planners require an enlightened approach to ensure the environmental, economic and social components are appropriately balanced to ensure sustainable business success. Although a relatively new player in the international E & P industry, Canadian Occidental Petroleum Ltd. has developed such an approach to EH&S management for projects in developing countries. Drawing from recent experience with a major project in Yemen, and others in the planning stages in several other developing countries, this paper presents a number of positive strategies and actions which are being applied in the many countries in which the company is active. Lessons learned and opportunities for improvement are presented for consideration by responsible operators working internationally toward the goal of environmentally sustainable energy development.
Organized For Safety
Authors: McCleary Michael D. , Schuberth Paul C. , Hining Dennis E.
Published: December 2007

The Exxon Company, International Drilling Organization (ECIDO) is committed to an injury-free workplace through continuous efforts by identifying and eliminating or managing safety risks associated with drilling activities. The newly developed and recently completed ECIDO Safety Management Program (SMP) strengthens this commitment by defining a comprehensive, management approved, organized framework for drill teams from which operations safety is managed both effectively and consistently worldwide. The SMP is proactive, focuses on positive recognition, promotes greater individual involvement, and gives part ow nership of the safety program at the rig level to the crews.
A Study Design for Follow-Up of Cancer Incidence and Mortality among Norwegian Offshore Oil Workers
Authors: Andersen A.
Published: December 2007

More than 30 years have elapsed since oil and gas were discovered under the sea bed around the Norwegian coast, and during these years there has been a rapid escalation of employees to 15-20 thousand. Work pattern and the health hazards vary among the different occupational groups, from drilling operation to canteen personnel. To our knowledge information of occupation linked with data on mortality for such a group of workers does not exist. An exception is the Healthwatch programme in Australia, but this study consists of few offshore workers only.

The purpose of present investigation has three features in relation to risk of cancer and cause of mortality in selected occupational groups. -collection of individual data on job history, chemical exposures, diet, smoking, alcohol consumption and leisure activity.-linkage of individual data with the Cancer Registry including date and cause of death.-analysis of potential risk of cancer and mortality in occupational groups working at offshore.

The study will include all present and past employees. At regular intervals the material will be linked to the Cancer Registry. Standardized incidence and mortality ratios (SIR) and (SMR) will be used in the analysis.
Waste Management Practices in the Gulf of Suez - Egypt
Authors: Ghzaly Sayed Mansour , Binegar James S.
Published: December 2007

The Gulf of Suez Petroleum Company (GUPCO) is the largest offshore oil producing company in Egypt. GUPCO currently produces 4(10,0(10 BOPD from over. 150 wells supported by 87 offshore producing platforms.As a leader of the Egyptian petroleum industry, GUPCO established within its strategies and goals a separate category covering safety, health and protection of the environment. This step was recognized and emphasized the importance of GUPCO’s role in protecting the Egyptian environment while producing oil and natural gas. This paper discusses the existing waste management practiccs of the Gulf of Suez Petroleum Company which were put into place to protect the Egyptian environment in the Gulf of Suez-Egypt and GUPCO’s associated operations
Auditing Environmental, Health and Safety Management Systems in E & P Companies: A Second Generation Auditing Program
Authors: Goldman D. J. , Guckian W. M. , Moore D. W.
Published: December 2007

This paper presents the development of a method of performing Management Systems Audits of Environmental, Health and Safety (EH&S) programs in upstream oil and gas companies. It describes how the results from the compliance auditing system presented in SPE Paper 25955, "Initiating an Audit Program: A Case History" were combined with a system categorizing EH&S activities into several management systems defined by regulations and good operational practices, and used to perform short term "Pareto-style" audits (e.g., 80% of the value from 20% of the time). A comparison is made of this type of audit model with the classic accounting audit model. Examples from Management System Audits of ARCO's foreign and domestic operations are used. Included are discussions of the economic benefit of performing EH&S Audits and the benefit of developing a method of auditing considering the new ISO 14000 standard for environmental auditing and the proposed ISO safety auditing standard.

The conclusions presented are that auditing by experienced personnel using an auditing template developed exclusively for upstream operations provides benefits to the company in the areas of compliance, management systems development and education of first line operations personnel as well as resulting in an overall reduction in the cost of an audit. A further conclusion will be that trends in international standardization appear to be mandating an EH&S auditing program for those companies planning to do business outside the United States.
Public Consultation and Risk Communication: The Brave New World
Authors: Denstedt Shawn , Verchere Bennett Jones
Published: December 2007

The general theme of the paper will be the increasing awareness of the public and ENGOs about environmental issues and perceived impacts of the oil and gas industry. The focus of the paper will be on the public consultation process and how the risks associated with oil and gas development are communicated to the public. The paper will review how the public consultation process has changed and the demands that stakeholders are making on the industry for constructive input into projects and information on the impacts of projects. The paper will consider the types of risk that oil and gas projects present: Impacts on air quality and related quality of life and health impacts;Contamination (soil and groundwater) that impact on environment, land values, and health;Worst case "catastrophe" scenarios and impact on public safety; andPerceived impacts of the public on quality of life.

As part of this section, the paper will consider a number of examples of projects in Alberta.

Finally, the paper will consider how a company should approach public consultation and risk communication. The paper’s conclusion will be that a proponent should consult broadly and present clearly the negative and positive impacts of the proposed project with a goal of creating an informed public, not to convince the public that the project is in its best interest.

The paper will also conclude that today’s public and environmental groups are more sophisticated and more organized than in the past. Regulatory authorities are demanding that accurate and comprehensive information be provided to stakeholders with a result that more and better information will be required upfront which will mean longer timelines for projects to get approved.
An Interactive 3D Fracture Modelling Environment
Authors: Swaby Peter A. , Rawnsley Keith D.
Published: December 2007

An original three dimensional (3D) fracture modelling environment which is designed to allow users to interactively construct near well fracture models suitable for use as input to fluid flow simulators is described. Data input consists of a surface model of the seismic scale structure, well fracture data, and user defined parameters. Sedimentary discontinuities and faults can be extrapolated from the wells in 3D. Within this near well model tension fractures can be generated using a genetic process which aims to reproduce the initiation, growth and interaction of fractures in order to create realistic fracture systems. Graphs are available for calibrating the fractures to assumed statistical distributions.
Thesis - Keeping the Management System "Live" and Reaching the Workforce
Authors: Primrose M. J. , Bentley P. D. , van der Graaf G. C.
Published: December 2007

Previous papers given to SPE conferences have described the Shell Group approach to Safety Management Systems and to Safety Cases. Their extension to HSE MS and to HSE Cases has also been addressed. Since 1984 the Enhanced Safety Management (ESM) programme within Shell companies has led to a significant improvement in the management of safety but it was only when structured management systems (based upon an understanding of the business processes) were introduced that true integration of HSE as a line responsibility became a reality. This paper describes the THESIS software package and the way that management systems have been made 'live' and how workforce involvemerU can be demonstrated.

The paper starts with the premise that "...work should not start before it is confirmed that essential safety systems are in place and that staff are accountable for this requirement. Where we cannot ensure safety, then operations should be suspended...".Line management needed a way of making this a real part of the job and of providing workplace personnel with an essential understanding of the risks that they face.

In Jakarta we stated that "Many of the early Safety Cases reviewed failed to provide a clear message that the operation's safety management system has benefited from the assessments made in preparing a Safety Case. They were regarded as paper exercises and a sterile documentation of what had been done, often by engineers or consultants. Without some form of 'energising' the system becomes just another book on the shelf. Since Jakarta we have been completing wotk on relational database software aimed at changing the Safety Case from being a paper document to a software based 'System' from which on-line reports can be extracted that add value to those managing the risk of the business. Changes to the electronic document can be readily undertaken and whilst still not painless the development and updating of a Safety or HSE Case is now much reduced in terms of time and effort enabling it to remain alive.

With the critical HSE activities and tasks specified and related hazards and effects identified and linked via a relational database, it is possible and realistic to provide to the workplace clear reports that describe the necessary controls in terms of the tasks that actually provide those controls.
Developing Health, Safety & Environmental Management Systems for Well Service Operations in the North Sea
Authors: Sealy I.
Published: December 2007

A health, safety and environmental management system has been developed to meet die business demands in the North Sea area. After reviewing published best-practice solutions a model that allowed the incorporation of existing programmes was adopted. Particular emphasis was placed on the need to implement a system that would promote continuous improvement, meet customer audit requirements and meet both current and projected future business requirements. In addition to formalising and documenting a number of existing programmes the system introduced two new programmes; competence assurance of ail operational personnel and internal auditing and benchmarking of management system performance. The system and its associated management tools are now being implemented in three countries in the North Sea area. Plans for future development of the system, particularly with respect to the integration of quality management programmes are also described.
Certification – The Same as Fitness for Purpose?
Authors: Montgomery M. E.
Published: December 2007

Classification and certification are not the same, and fitness for purpose may or may not be determined by either. This paper compares and contrasts classification, certification, and fitness for purpose. Included are not only the general policies and definitions used by the major classification societies, but also how these services fit into the various quality certification schemes like ISO and API. As a result, when you have a need for third party verification of "quality", you will know what you should specify and the correct terminology used by those in this industiy.
Unique Gauge Structure and Other Bit Modifications Improve Drilling Efficiency of Baram, Baronia Fields
Authors: Ngieng J.Nk. , Khalid M.Z. , Edmondson M. , Skari D. , Robinson R.
Published: December 2007

The introduction of roller cone bits incorporating a unique gauge cutting mechanism, in combination with other gauge and hydraulic modifications, dramatically increased drilling efficiency and lowered the costs of two major development projects offshore Sarawak, Malaysia. The aforementioned technical modifications and other continuous improvement practices, which resulted from close interaction between operator, contractor and bit company, saw drilling costs reduced nearly US$378,000 on the Baram and Baronia development programs.

This paper describes the evolution of operator-driven tool development and operational practices that led to increased footage and penetration rate per bit in the interbedded shale, sandstone and limestone intervals intrinsic of the directional wells drilled offshore Sarawak. The authors will review the two fields (Baram and Baronia), detailing the tool and operational modifications that significantly improved the economics of the development drilling campaign.

Introduction

In early 1994, Baram Delta Operations (BDO) launched an aggressive development drilling program on its Baram and Baronia fields, two of nine structures discovered offshore Lutong, Sarawak, Malaysia. Fig. 1 shows the location of the two fields on the SK15 concession at the mouth of the Baram River.

A total of 61 wells have been drilled in the development program, including 33 on the Baram field - discovered in 1963 with exploration well Baram-1 - and 28 on the Baronia field, which was discovered in 1967.

The two fields are located in the structurally complex Baram Delta Province, where nearly 730 hydrocarbon-bearing reservoirs have been identified. The region features abrasive intervals and extremely depleted reservoirs that possibly overlay severely overpressured formations. Generally, the structures are complexly faulted, comprising interbedded sand and shale with limestone and dolomite intervals. The sands, which are fine and angular, tend to be sharp and highly abrasive. Fig. 2 is a cross-section of the Baram field, highlighting its structural complexity.

The often unpredictable geology of the Baram Delta Province has caused numerous development drilling problems, particularly in the deeper wells. Chief among the drilling problems are stuck pipe, lost circulation and abrasion-induced drillstring washouts.

Owing to its complexity and highly troublesome characteristics, the Baram field was selected as the testing ground for most of the experiments directed at improving efficiencies in the development drilling program. The knowledge gained in the Baram experiments was subsequently implemented in the younger Baronia field.

BDO Drilling Efficiency Program

A typical well in the recently concluded Baram Delta Operations campaign was drilled directionally from either a cantilevered jack-up or from a tender-assisted rig on the "F" platform. On the average, a BDO well was drilled to a total measured depth of 8,000 ft.

P. 367
Water Frac Applications In High Island 384 Field
Authors: Claiborne E.B. , SAUCIER R. , WILKINSON T.W.
Published: December 2007

A frac pack technique using water, herein referred to as a water frac, has been developed for use in wells where the goal is to achieve effective sand control at minimal cost while bypassing wellbore skin thus increasing well productivities. This increased productivity is accomplished by a properly designed, length limited, hydraulic fracture, created and propped with non-damaging fluid/prop that provides a highly conductive flow path through the wellbore damaged zone, in conjunction with a proper gravel packed completion. The process is applicable to intervals comprised of multiple pay zones by using a multi-stage water frac technique. The entire process of creating and packing the fracture(s) and gravel packing is accomplished using a properly defined gel free brine.

The multi-stage water frac process has been applied and evaluated in the High Island 384 Field. Job evaluations herein illustrate the process. The process has also been applied using uncrosslinked gelled fluids in this field as well, with the evaluations to date indicating the water frac results to be superior. Comparisons with larger sized frac packs in a similar area also indicate the water fracs to be equal or superior to the frac packs in well performance.

In the following, the process of a water frac will be described, typical field pumping techniques will be provided and field applications and results will be presented.

Introduction

Bypassing near wellbore damage in relatively high permeability formations using a propped hydraulic fracture is an increasingly well known and commonly applied practice. Wellbore damage is typically relatively close to the wellbore (ie: three times wellbore radius) and hence to bypass wellbore damage requires only a short fracture (+/– 2 ft). More generally, for relatively high permeability formations, the fracture does not have to be long to optimize the production rate, as illustrated by Figure 1. Figure 1 shows that a fracture length of 5-10 ft will deliver virtually all that can be produced from many high permeability formations. The small fractures can be created and propped effectively with brine, as opposed to more viscous, highly complex fluids. These type treatments are herein referred to as Water Fracs (WF). These short conductive fractures that bypass damage, coupled with an effective gravel pack constitute an effective, sand free, high productivity completion. This WF process is not to be confused with high rate water packs that are pumped below fracture pressure.

The following describes the water frac process, and applications on the HI 379B platform. Also included is a brief background and history of the HI 384 area leading to the application of the WF process, as well as typical treatments and pumping techniques. Discussion of results follow and include the evaluation of field data via history matching, post frac buildup analysis (both initially and over time), other observations from the data, results, and conclusions.

P. 419
Hydraulic Fracturing for Control of Sand Production and Asphaltene Deposition in Deep Hot Wells
Authors: Ortega L. , Brito L. , Ben-Naceur K.
Published: December 2007

The North of Monagas giant field in Venezuela has been produced since the late 80-s. Depth ranges from 12000 to 20000 ft (3,600 to 6,000 m). Wells in the field have experienced early in the production cycle both problems of sand production and asphaltene flocculation. A multidisciplinary team was created to define ways to optimize production from the field.

The paper first addresses the methodology used to identify the source of the sanding problem, including extensive mechanical analysis of the formation, with tri-axial testing and sanding critical flow gradient analysis. The effectiveness of the initial strategies of optimization of choke size, and selection of perforated intervals and gun sizes is evaluated. The onset of asphaltene deposition was analyzed, and it was determined that most occurring problems were related to drilling and production practices.

To solve both problems, by modifying pressure drop and flow profiles, a hydraulic fracturing strategy was implemented in the field. Special care was given to the particular well conditions (close-by dual tubing completion, with potential risk of communication, thick and multi-layered geometry), in addition to expected high treating pressures and sensitivity of formation fluids to thermal shocks. A detailed pre- and post-fracturing well testing procedure was adopted which allows for an optimization of the fracture length, and comparison of results with predictions. Prior to the main fracture, calibration treatments were performed; calculated fracture heights were compared to the ones determined from temperature logs. A new technique to determine permeability from mini-fracs using the theory of impulse testing was also applied. Finally, production logging after the frac and a build-up were used to assess the validity of the predictions.

Introduction

The giant North of Monagas field lies in the East of Venezuela, in an area of over 400 km2 (Fig. 1). Its structure is an asymmetric anticline, with the Naricual formation (late Oligocene) being the most important feature, and thickness of over than 1500 ft, at depths between 12000 and 20000 ft (3.6 km to 6 km). The field was discovered in the 1980's. Despite high reservoir pressures, several wells have experienced severe sanding problems, combined with asphaltene deposition in the downhole tubulars. In addition to production losses, the frequency of well intervention to clean up downhole flow obstructions (via workover, snubbing or coiled tubing), and the complexity of working in wells with dual completions has created a major challenge. Another problem has been in the erosion of surface equipment, due to sand flow.

In order to provide viable long-term solutions to both problems (sand production and asphaltene), a work group between Corpoven and external laboratories to identify the cause of the production behaviour, and implement efficiently the techniques, with proper evaluation.

P. 449
Heterogeneous Formation : Assessment of Vertical Permeability Through Pressure Transient Analysis - Field Example
Authors: de la Combe J.-L. Boutaud , Deboaisne R.M. , Thibeau S.
Published: December 2007

In strongly vertically heterogeneous reservoirs, the oil flows to the well through the high permeability layers. Often in this kind of reservoirs, most ofthe original oil in place is stored in the low permeability layers, which are not contributing directly to the well production. This oil can only contribute to production if vertical communication occurs between low permeability layersand high permeability layers. Because the vertical permeability has a major impact on oil recovery, the evaluation of its uncertainty is a key factor for economic evaluation of the field.

This paper demonstrates how uncertainties in vertical permeability were deduced from pressure transient analysis on a field example in the Middle East. The classical multilayer analytical solution which represents crossflow between layers with the pseudo-steady state assumption was used. This paper highlights a practical method to compute the whole range of vertical permeabilities which honor the well test data. The use of these computed vertical permeabilities in reservoir simulation is discussed.

Introduction

Drill-stem tests were performed on three appraisal wells in a highly vertically heterogeneous carbonate formation. In order to evaluate the productivity of the wells, an acidization was performed on each well during the test before the buildup data acquisition.

The geological model has divided the reservoir into high flow capacity layers and low flow capacity layers, sometimes separated by a tight layer that can play the role of a permeability barrier. The permeability of the high flow capacity layer is due to vuggy porosity.

The build-up data were matched using the classical multilayer model. The well test analysis theoretically allows to define the following reservoir parameters : horizontal permeability and skin of each layer, storativity ratios and interlayer crossflow coefficients (lambda). However, the information provided by the derivative signature is not able to characterize such a bignumber of parameters. It is the reason why some of these parameters are fixedbefore the interpretation, thanks to an a priori knowledge of the reservoir. Then, the non fixed parameters are computed from the well test interpretation. They are considered as the results of the analysis. Among this computed parameters appears lambda which characterizes crossflow between layers. However, reservoir engineers prefer to deal with vertical permeability rather than interlayer crossflow coefficient.

This paper states that the solution in terms of vertical permeability is nonunique and shows how to compute its complete range consistent with the test data. Afterwards the impact of layering is discussed.

P. 399
Multiphase Pumping - Operation & Control
Authors: de Salis J. , de Marolles Ch. , Falcimaigne J. , Durando P.
Published: December 2007

This paper reviews field issues related to the planning, installation and operation of the helico-axial multiphase pumps.

Interest for multiphase production, which leads to simpler and smaller in-field installations, is primarily dictated by the need for more a cost effective production system.

Multiphase pumping is essentially a means of adding energy to the unprocessed effluent which enables the liquid/gas mixture to be transported over long distances without the need for prior separation.

The Poseidon helico-axial pumps, under normal operating conditions, are largely unaffected by process fluctuations at pump inlet (changes in pressure, liquid or gas flow rate). They have demonstrated a stable behaviour (self-adaptive capability with regards to instantaneous changes).

A multiphase pump set is designed to operate under changing/fluctuating process conditions.

An important issue related to pump operability and flexibility has to do with the driver selection: fixed speed vs. variable speed In some cases a fixed speed drive provides sufficient operational flexibility. In other cases variable speed can be chosen.

Pump operation & control strategies are presented and discussed.

Recommendations and guidelines for the field system designer are given.

Introduction

When the production of a marginal field or a group of remote wells is considered with an existing central gathering system the traditional options for field development are:–natural flow,–artificial lift,–in-field separation with crude oil transfer pumps, gas to flare, or gas compression systems.

With the recent field deployment of numerous multiphase pumps (MPP) new approaches to field development and production have been demonstrated. Typically helico-axial MPP have accumulated over 35,000 operating hours with an average availability of approximately 90%.

Considering multiphase flow transient behaviour the operability of MPP is highlighted in the case of a declining offshore field with an increasing water cut.

Different levels of pump control are defined depending on the operational requirements. Building on previous ideas a novel control system is introduced.

Pump Specification

The multiphase pump selection cannot be based solely on one defined operating point (main duty point) as it is commonly done for process pumps or compressors for refinery duty. Field experience shows that actual operating conditions change during the field life and may be different from predictions.

Therefore multiphase pumps should be designed to be capable of facing different operating parameters by having a wide working envelope.

Flow rates and pressure predictions are bound with uncertainty. The design of production facilities is generally based on extrapolations from the results of exploration well tests, delineation wells and reservoir characterisation.

As a result, when the production wells are drilled and completed, the actual production data may be different from the prediction.

P. 193
Completion Ranking Using Production Heterogeneity Indexing
Authors: Reese R.D.
Published: December 2007

This paper describes an analysis method for production data referred to as heterogeneity indexing which quantifies well performance anomalies for the purpose of assessing completion efficiency. It has been proven useful for determining the most successful completion practices in a given area and formation as well as a surveillance tool for primary and secondary recovery operations.

Utilizing computer aided normalization methods, heterogeneity signatures and indexes may be extracted from time-based production data. The paper illustrates how to calculate these indexes, integrate this information with petrophysical and completion data, and then interpret it for the purpose of assessing the effectiveness of various types of completion methods. In developing this method, fluid simulation modeling of various types of reservoir heterogeneities were used to develop a series of type curves. The signatures in these type curves exhibit characteristics which have been shown to relate to reservoir properties and completion efficiency.

Introduction

When subjected to appropriate analysis methods, oil and gas production data exhibit well performance anomalies useful to the assessment of completion efficiency. This information can be used to rank the effectiveness of different completion methods being used with a particular producing formation in a given geographical region. Completion efficiencies are also useful for identifying specific wells with poor or superior performing completions. An analysis method referred to as heterogeneity indexing may be used for this purpose. It involves the computer analysis of historical production data which is then integrated with available completion and rock data to develop performance ranking criteria and assessment tools.

Production Heterogeneity Indexes

Anomalies are observable in oil and gas well production data that are attributable to one or more of the following factors:

Time well is on production Reservoir pressure Completion method and efficiency Reservoir quality and tank size With proper analysis methods, the effect of the first two factors can be normalized out so that assessment of completion efficiency and/or reservoir quality becomes possible. This assessment is accomplished with heterogeneity indexing which may be generally defined as follows:

where HI Fluid is the heterogeneity index for any type of fluid production ratio. Fluid may be oil, gas, barrels of oil equivalent, total liquid, gas-oil ratio or water cut and may consist of either "rate" or "cumulative" numbers.

A well with no heterogeneity (an average well for the field or formation) has an HI equal to 1.0. When HI is examined over n periods of time, a heterogeneity signature is obtained. An example is shown in Figure 1. The shape of this signature, relative to the benchmark of HI = 1.0, can be indicative of completion or reservoir anomalies.

P. 303