bluuebunny/crossref_metadata_2025 huggingface dataset:
Improving the Petrophysical Assessment of Rock-Fluid Systems With Wide-Band Electromagnetic Measurements
Authors: Toumelin E. , Torres-Verdín C. , Bona N.
Published: December 2007

Due to their sensitivity to ionic content and surface distribution, wide-band electromagnetic (WBEM) measurements performed on porous rocks are influenced by petrophysical factors as diverse as fluid saturation, pore morphology, thin wetting films, and electrically charged clays. In general, all of these factors simultaneously coexist in fluid-saturated rocks, and therefore a comprehensive and accurate physical model is needed to correctly interpret WBEM measurements in terms of petrophysical properties. Traditional mixing laws fail to quantify the collective influence of various petrophysical parameters on WBEM measurements. As a result, no general method is currently available for the accurate petrophysical interpretation of dielectric measurements. The objective of this paper is to quantify the sensitivity of WBEM measurements to a large array of petrophysical properties, and to show that they naturally complement with NMR measurements. To this end, we develop a comprehensive numerical model that successfully reproduces the kHz-to-GHz dielectric dispersion measured on a variety of rock and fluid conditions, wettability, and clay content. Our model is based on the solution of Maxwell's equations at the pore scale and incorporates explicit geometrical distributions of grains, fluids, and wet clays, constructed from core pictures and measurements. Comparison of WBEM and NMR measurements emphasizes the complementary nature of the two techniques, especially in the assessment of wettability, fluid saturation, pore connectivity and morphology, hydraulic pore coupling, and pore size distributions. Because our approach integrates all of these petrophysical features, we can assess their relative influence on borehole kHz-GHz WBEM measurements acquired in hydrocarbon-bearing rocks.
World's First Coiled-Tubing Underbalanced Casing Exit Using Nitrogen Gas Mist as the Milling Fluid
Authors: Webster B. , Pitman M. , Pruitt R.
Published: December 2007

This paper describes the world's first true coiled tubing under balanced casing exit using a Nitrogen (N2) gas mist as the milling fluid, which allowed a well in Sharjah's Sajaa field to remain live throughout the casing exit, ensuring uninterrupted gas production. Previous attempts to mill a window using a N2 gas mist with conventional milling technology proved unsuccessful. This was largely due to the lack of cooling and lubricity of the milling fluid resulting in a rapid deterioration of the window mills. Subsequent windows were milled using water only which resulted in massive fluid losses to the formation, due to the low reservoir pressures within the field, and more importantly caused interruptions to existing gas production.

The technology described in this paper allowed gas production to be maintained throughout the window milling operation and resulted in a dramatic reduction in fluid losses to the formation and a reduction in overall casing exit time. Following the casing exit, the build and lateral drilling assemblies were deployed through the window at the first attempt, allowing uninterrupted progression to the under balanced drilling phase. This technology has helped to extend the life of the Sajaa field and secure the future of the Sharjah Coiled Tubing Drilling (CTD) project.
Measured and Predicted VIV Responses of Faired Drilling Riser Models
Authors: Lee L. , Allen D. W. , Henning D. L.
Published: December 2007

This paper discusses the measured vortex-induced vibration (VIV) responses of faired drilling riser models and predictions from computer codes. Experimental data indicated that tail fairings are very effective at suppressing VIV of drilling risers. Comparisons are made among the test results, predicted responses from the calibrated model, and the calculations from an un-calibrated model. Examples are given that clearly demonstrate the importance of testing and computational model calibration.
Magnus Field: Reservoir Management in a Mature Field combining Waterflood, EOR, and New Area Developments
Authors: Moulds T. P. , Trussell P. , Haseldonckx S. A. , Carruthers R. A.
Published: December 2007

Magnus is a high productivity oil field in the northern North Sea. First oil was produced in 1983 and the plateau of 150 mstbod ended in 1995. During the 10 years post-plateau a variety of reservoir management techniques have been employed to arrest decline rate. Now, through exploitation of a gas injection EOR opportunity the oil rate is again rising. And looking to the future a major project to increase reservoir access by adding drilling slots is being executed that will maintain significant oil production beyond the next decade.

The field remains opportunity-rich, prioritisation of drilling targets is complex: EOR wells vie with infill waterflood targets and extended reach wells to the field periphery. The non-uniqueness inherent in any reservoir simulation history match means that a conventional full field model cannot sufficiently reduce uncertainty on future drilling and facilities decisions. A particular challenge emerges when the reservoir process changes and future performance may be sensitive to aspects of reservoir description that have little influence on the history match. The gas injection project presents such a challenge.

A solution is found through the emergence of genetic algorithm techniques applied to reservoir simulation. A semi- automatic workflow is developed where input parameters are varied, each combination of parameters yielding a quantitative measure of history match quality. The methodology is notable for generating multiple, significantly different, reservoir descriptions, each with an acceptable history match but with potential for quite different performance during prediction. This approach better determines those parameters that control performance; it increases the exploration of uncertainties and allows development of robust mitigation strategies.

We present results of genetic algorithm techniques applied to dynamic and static full field model descriptions and to the development of pseudo relative permeability curves to provide effective flow functions for all phases in the full field model. We show how the development of a reservoir simulator that is able to address diverse development options against the uncertainty of reservoir description has impacted reservoir management.
Understanding the Effects of Reservoir Changes in Sand-Control Completion Performance
Authors: Norman W. D. , Pourciau R. D. , Dusterhoft R. , Schubarth S.
Published: December 2007

Sand-control completion performance has been a key point of discussion within our industry for several years. Widely varying values of skin and PI exist and arguments have been made to oppose or support different completion techniques currently available. In many cases, these arguments are made in attempts to promote certain completion techniques when more time should be spent understanding the probable sources of the condition.

This paper examines closely (1) how reservoir properties in the near-wellbore region can change significantly over time under production conditions, and (2) how these changes can affect well performance over time. It looks at the significance that reservoir compaction can have when reduction in permeability is accounted for and how detrimental this compaction can be to well productivity.

In reservoirs subject to compaction, the behaviors of radial completions are compared to frac-pack completions over the life of the well. The paper demonstrates that although the conductive fracture may not be a dominant factor in well productivity early in the life of the well, it can become very significant in maintaining well productivity and performance later in the life of the well. In effect, these completions can be designed to improve well performance over time, and in many cases can result in decreasing skin factors with time, thus minimizing the decline in productivity.

Reservoir modeling was performed that considered near-wellbore compaction and the presence of a high-conductivity fracture; this model agreed well with observations made from several deepwater developments.

A detailed case history is also presented wherein sufficient reservoir evaluation was conducted over time to validate the effects of compaction and the long-term performance improvements that can be achieved using frac-pack completions with these reservoir conditions.
Leak Sealing on a Water-Injection Line in the Foinaven Field, West of Shetland, using Platelet Technology
Authors: McEwan I. K. , Ryan N. J. , Chirnside I. B. , Meldrum A. G. , Shaw A. , Alexander P. D. , Stebbings T. F.
Published: December 2007

Platelet™ technology is a new and novel method of sealing and locating leaks in pressurised pipelines. It is based on the remote injection of small mechanical objects into the line. These are then conveyed to the leak site by fluid forces and once there act in such a way so as to form a seal, thereby stemming the flow through the leak. Platelets™ also have the capacity to enable leak location by the use of tracers added to the platelets™ prior to injection.

This paper describes the first ever deployment of platelet™ technology in the field. The application took place in a 10" water injection line in BP's Foinaven Field, West of Shetland during the autumn of 2004. The outstanding success of this operation rested on the detailed preparatory work which encompassed flow loop testing, hazard analysis, numerical and analytical modeling, materials analysis and pressure vessel testing. Crucially the number of platelets™ used was sufficiently small so that any threat to the reservoir was deemed to be negligible.

As this was the first use of platelet™ technology in field conditions, the deployment of the platelets™ was undertaken during dye injection so that progress could be monitored by ROV. Sudden and complete cessation of the dye stream from the leak confirmed that a seal had been effected. A pressure fall-off test immediately after the platelet™ operation showed a significant improvement over the previous test conducted before the operation. The seal allowed BP to increase water injection from 141,000 to 154,000 bbl/day with an immediate affect on reservoir production.

The outstanding success of the operation has introduced a new tool to provide a means of rapid top-side response to further failure in winter months when sub-sea intervention and DSV availability is less than certain.
Clair Field—Managing Uncertainty in the Development of a Waterflooded Fractured Reservoir
Authors: Clifford P. J. , O'Donovan A. R. , Savory K. E. , Smith G. , Barr D.
Published: December 2007

Clair field came on production in February 2005. Clair is a large oil reservoir (>4 billion bbl STOIIP), 75 km west of Shetland. It is the largest naturally fractured reservoir developed in the UK, and is recovered by waterflood. Its 28 year appraisal period reflects the high reservoir complexity, relatively poor quality conventional seismic image, and uncertain impact of the conductive fractures.

This paper compares early Clair production with pre-drill expectations. Its primary focus is on reservoir uncertainty, and how the drilling sequence and data acquisition are managed to allow rapid and flexible response to learning, given an expectation of surprises. Clair is not pre-drilled, and the preferred well locations and design will change. A condition of responding rapidly is a hopper of well options, kept filled with diverse well types and locations, from which appropriate wells are selected using current knowledge. Key decision points in the sequence are identified in advance and options at each point evaluated against reservoir scenarios. This process allows planning for potential outcomes, generates the required hopper wells and identifies data requirements for future decisions.

Clair well-planning requires integration with reservoir surveillance and modelling. Early surveillance focuses on reservoir pressure response. All wells (including injectors) have a permanent down-hole pressure gauge, RFT data acquisition and a baseline production log. These data establish reservoir connectivity, injection response, and controls on productivity and injectivity. Also important is seismic data calibration against log and core information, to refine models of the natural fracture distribution. Water movement through fractures is expected and will become a surveillance focus.

Clair reservoir uncertainty is represented in sets of static and dynamic reservoir models which express the full uncertainty range consistent with data. At start-up, a wide range of fracture models, with diverse outcomes, can be consistent with the limited dynamic data. As new data arrive, the objective is to condense the range of models, which continue to be diverse, but must also be consistent with all historic data at the end of every month. These models inform drilling programme decisions, reflecting both the continuing uncertainty and rapid learning.
Quantitative History Match of 4D Seismic Response and Production Data in the Valhall Field
Authors: Kjelstadli R. M. , Lane H. S. , Johnson D. T. , Barkved O. I. , Buer K. , Kristiansen T. G.
Published: December 2007

Permanent ocean-bottom seismic cables have been installed in the Valhall Field, offshore Norway. Five seismic surveys were acquired from the permanent system between October 2003 and April 2005, in addition to two towed-streamer surveys acquired in 1992 and 2002. The various 3D seismic data sets show strong time-lapse or 4D effects resulting from primary production. During the same time period an extensive drilling program has provided high-quality data on reservoir pressure, pressure gradients, and reservoir fluid distribution in the field.

This paper outlines how changes in seismic attributes were generated synthetically from a reservoir simulation model and compared against observed 4D seismic data in one area of the field. An objective function describing the misfit between the simulated and measured data was defined using both seismic and conventional production data. BP's Top-Down Reservoir Modelling (TDRM) technology1 was used to generate multiple reservoir descriptions that would minimize the objective function. This involved computer-assisted history matching with a genetic algorithm that varied more than 60 parameters in the reservoir simulator to improve the overall history match.
Formation Pressure Testing While Drilling for Deepwater Field Development
Authors: Fletcher J. , Seymour G. , Flynn T. , Burchell M.
Published: December 2007

The Foinaven, Loyal and Schiehallion fields lie West of Shetland, some 170 Km west of Sullom Voe. These fields, operated by BP, consist of a number of channelised sandstone reservoir sequences of Paleocene age. They have been developed by high angle/horizontal production and injector wells, the placement of which is critical to the effective drainage of the reservoirs. The reservoirs have significant compartmentalisation due to a number of faults and facies boundaries which means that formation pressure data, coupled with other surveillance information, are critical in ensuring correct well placement. Additionally, formation pressures are required by completion engineers to determine completion string geometry. Until recently, the only available method for acquiring these formation pressures was to run a wireline tester on drillpipe, after the well had been drilled. As all other FE logs were generally acquired using LWD this was time consuming and expensive on the new generation rigs required to drill in this area. In 2004, the first pressure testing LWD tools were deployed in these fields, allowing formation pressure data to be acquired as part of the drilling process, thus allowing real-time decisions relating to wellbore trajectory to be taken, and eliminating additional pipe conveyed wireline runs. This paper discusses the process which was used to validate the measurements, quality control of the real time and memory data, and examines some of the advantages and disadvantages of acquiring formation pressure measurement as the well is drilled rather than after reaching TD.
The Hod Geohazard: A Unique Overpressured Interval—Cooperation in Its Recognition, Evaluation, and Risk Mitigation
Authors: Holm G. , Owens J. , Page G. , Ritchie A.
Published: December 2007

While drilling wells in the Total operated Franklin, Elgin and Shell operated Shearwater HPHT fields of the UK central North Sea, gas was often encountered over intervals in the Upper Cretaceous Hod Formation. In addition, gas continued to bleed occasionally into the well until the section TD. During the completion phase of a Franklin well, the annulus pressure started to rise and a temperature and gamma ray survey indicated that fluid was bleeding into the annulus from a thin zone within the Hod Formation. Given the common issues, the so-called "Hod Geohazard" was identified for further shared study between the two operators.

Open hole logs over the Hod Formation for three of the Franklin wells were used to quantify the hydrocarbon in this interval. Three thin limestone horizons were recognised from a review of the drilling gas and cased hole gamma ray and acoustic data. An overlay technique was applied to the gamma ray and acoustic logs, which showed that two of the limestones were tight, but the third, three meters thick, had apparent porosity.

The overlay technique was then applied to the development wells, where only gamma ray and acoustic data were available. This allowed a qualitative estimation of the degree of porosity and permeability for those wells. The results indicated that the three limestone horizons had a regional distribution, although with varying degrees of porosity. This then provided a predictive tool to assess which wells were likely to have live annuli when turned over to production.

Identification of this Geohazard as a tight, overpressured gas bearing horizon has been important. It was realised that cemented casing was unlikely to hold this gas back during the production lifecycle of the wells. Consequently, casing annulus pressure management systems were installed on the facilities. In addition, increased awareness of Hod gas influx during drilling was included in the planning of subsequent wells in the region.

The key to these improvements was the collaboration of operators sharing experiences. It resulted in improved drilling and completion practices for both companies during their projects. The lessons learned can be applied by other operators in similar challenging HPHT environments.
Non-Darcy Flow in Hydraulic Fractures: Does It Really Matter?
Authors: Miskimins J. L. , Lopez-Hernandez H. D. , Barree R. D.
Published: December 2007

In recent years, non-Darcy flow has seen a significant increase in interest in the petroleum industry, especially in flow in fractures—both artificial and natural. In hydraulic fracture stimulation, non-Darcy flow can have a major impact on the reduction of a propped half-length to a considerably shorter "effective" half-length, thus lowering the well's productive capability and overall reserve recovery. These non-Darcy flow effects in propped fractures have been typically associated with high flow rates in both oil and gas wells.

This paper shows that non-Darcy flow effects have an impact on the performance of a hydraulically fractured well even at low flow rates. Although not as drastic as the effects on high flow rate wells, reductions in flow capacity of 5-30% can be realized in low rate wells. Such reductions are due solely to non-Darcy effects. When combined with other concerns, such as multiphase flow, the production reduction effects are even greater.

Development of a simple spreadsheet is provided to aid engineers in assessing the impact non-Darcy flow may have in a given situation. The spreadsheet is not intended to replace more in-depth investigation of non-Darcy flow effects but instead provides a conduit to assess the sensitivity of certain parameters in a hydraulic fracture stimulation situation.

For comparison purposes, results of the loss in long-term dynamic conductivity on well performance and cumulative gas recovery over time in low permeability reservoirs are also presented. These calculations were performed using dynamic conductivity loss calculations coupled with a transient gas reservoir simulator. These results showed that for the cases examined, non-Darcy effects could reduce cumulative gas production by up to 18.1% over a ten-year period.
Numerical Investigation of Horizontal Well Performance with Selective Completion
Authors: Kalita R. , Jalali Y.
Published: December 2007

This study presents a numerical method of determining the sandface completion profile of a horizontal well to achieve a prescribed production objective. A technique is developed to determine the completion profile that maximizes an objective function (e.g., cumulative production) for a given well operating program in a defined reservoir environment. Sandface completion is modeled in terms of a connection factor between the reservoir gridblocks adjacent to the well and wellbore segments. Well performance is evaluated in terms of cumulative production within specified operational constraints (maximum rate, minimum bottomhole pressure). The method uses a finite-difference technique to determine the sensitivity of well performance to changes in the wellbore-reservoir connection profile. The optimum connection profile is determined by a gradient-based technique using the sensitivity coefficients from the finite-difference method. This approach can be used to either plan the sandface completion during the well design stage, or to optimize the completion after drilling based on measured petrophysical and flow properties of the formation. Examples are given in the paper covering both water-and gas-drive problems.
Improved Reservoir Management Through Integration Of 4D Seismic Interpretation, Draugen Field, Norway
Authors: Mikkelsen P. L. , Guderian K. , du Plessis G.
Published: December 2007

4D seismic interpretation plays a key role in the reservoir management of the Draugen Field, situated offshore Norway. Time lapse seismic surveys of exceptional quality conducted in 1990, 1998, 2001 and 2004 have all shown outstanding areal and vertical definition of the water movement towards the producing wells.

Excellent reservoir properties with relatively few high rate wells and an expected recovery factor exceeding 60 percent make Draugen one of the best performing fields offshore Norway. The field has a simple geology, however, the reservoir structure is relatively uncertain due to the low number of well penetrations for calibrating the structure. Fortunately, the 4D seismic interpretations have largely compensated for this shortcoming by providing improved lateral control for refining the reservoir simulation models.

All of the 4D interpretations conducted so far have indicated the need for simulation model changes such as modified reservoir volumes in certain areas, revised fault transmissibilities, and the need for improved relative permeability characteristics. Integration of the 4D interpretation results has greatly improved the various Draugen reservoir simulation models enabling improved forecast and reserve estimates as well as better business decisions. Effects on the field reservoir management have included revising the water injection strategy, converting a producer to injector, re-positioning a development well and drilling an appraisal well.
Offshore Implementation Of Through-Tubing Dynamic Annulus Pressure Controlled (DAPC) Coiled-Tubing Drilling
Authors: Laird A. , McFadzean K. , Edgar J. , Harty I.
Published: December 2007

Dynamic Annular Pressure Control (DAPC) is a new technology that allows accurate control of downhole pressure in a well. DAPC was used in conjunction with Coiled Tubing Drilling (CTD) on the Gannet GA-03 well between February and April 2005. This report describes the selection, design, testing and field performance of the recent DAPC-CTD Gannet project.

The original horizontal wells in the Gannet Alpha reservoir were positioned in the middle of the 53ft oil rim. Upward migration of the oil rim, due to gas production, meant that it had moved beyond the reach of the original horizontal wells. As a result, these had watered out, and many of the wells had been shut in for several years.

A review of the reservoir model in 2000 revealed that much of the migrated oil, some 25-35% of the STOIIP, was stranded and would be lost forever unless infill drilling was performed.

Re-instatement of the drilling rig was considered uneconomic and CTD was selected as a lower cost, technically feasible option, though Shell's history with CTD showed mixed success, indeed a five well campaign in 1999 was cancelled after catastrophic failures in the first two wells. The primary issue in these wells was associated with managing the downhole pressure to find a balance between wellbore stability and differential sticking. The main subsurface challenges on the Gannet are the same and as such overcoming these hurdles was of prime importance.

CTD and DAPC offered a novel solution, and this report details the development of the Gannet CTD project through feasibility, concept selection, detailed design, and successful execution.
Tuning an Equation of State—The Critical Importance of Correctly Grouping Composition Into Pseudocomponents
Authors: Al-Meshari A. A. , Zurita R. A. A. , McCain W. D.
Published: December 2007

A limited number of multiple carbon number groups are used in compositional simulation to represent the heptanes plus fraction of the petroleum mixture. The selection of the single carbon number groups that are grouped into the multiple carbon number groups has a severe effect on the calculation of the position of the critical point of the mixture. This in turn strongly affects the maximum constant volume line of the phase diagram at reservoir temperature. If the maximum liquid volume at reservoir temperature is nearly correct then the match of other pressure-volume-temperature data of a laboratory study is relatively simple. A correlation has been developed to determine the correct grouping of the multiple carbon number groups. Also it was found that only two multiple carbon number groups are required to represent the heptanes plus fraction of a petroleum mixture.
Gas Management, Reservoir Surveillance, and Smart Wells—An Integrated Solution for the Bugan Field
Authors: Dolle N. , Singh P. , Turner R. , Woodward M. , Paino W. -F.
Published: December 2007

Proposal

This paper describes a study to investigate the preferred gas management strategy, the required reservoir surveillance program and the enabling well completions to provide an integrated solution for the optimum development of the Bugan Main Block.

The main drive mechanism for the Main Block reservoirs is a combination of solution gas drive and gas cap drive. Conservation of reservoir energy, through controlled gas production, is crucial to maximize reserves. This is undertaken by the creation of a Gas Management Strategy (GMS) aimed at maximizing the ultimate recovery of oil through control of the reservoir GORs.

In reality, the ideal gas management strategy, in terms of initial GOR plateau and ramp-up schedule, depends on the actual reservoir performance. Value of Information studies indicate that reservoir surveillance is required to capture both potential up and downsides in terms of available reservoir energy. This surveillance would allow the adjustment of the gas management strategy to maximize value and safeguard reserves.

Smart completions with inflow control valves (ICVs) and down hole pressure gauges (DHPGs) meet the surveillance requirements and the initial expenditure has been compared with lifecycle costs of conventional CTU well interventions. It is concluded that running a smart completion is preferred over a conventional completion, because of lower lifecycle costs, improved well and reservoir surveillance, lower operational risks and reduced production deferment.
Substance Abuse Testing Program: A 10-Year Experience
Authors: Khantong A.
Published: December 2007

To ensure the safety of the workplace and employees, Unocal Thailand established a Substance Abuse Policy in 1994. The testing program employs random and mandatory selection procedures to deter individuals from using prohibited substances. Both urine tests and breath tests are administered. The program has been challenged several times by employees with various allegations, including violation of privacy, breech of terms of employment, the validity of the test, and overall legitimacy of the process. Because of its open, transparent and constructive approach, the program has over time become accepted as an effective safety measure for living and working together. The program has been regularly updated to ensure that procedures and testing methods are performed consistently and fairly, without losing the primary objective of deterrence.
Use of Pressure-Activated Sealant to Cure Leaks in Subsea Wells—A Case Study in Campos Basin
Authors: Rodrigues V. F. , Gonçalves G. G. , Rusch D. W. , Videira J. L.
Published: December 2007

Offshore oil and gas production systems are complex systems comprised of wells, flow lines, a variety of subsea and dry subsystems, production platforms and export lines. Hydraulic systems are extensively used in offshore production systems, particularly for valves control and operation. Failures in hydraulics systems may cause loss of redundancy, loss of control and well shut-in with economic losses and risks to system integrity and environment. Leaks, mostly internal, represent one of the most common failures in the hydraulic systems. The conventional approach to repair these leaks makes use of rig and/or support vessels, being time and money consuming, not mentioning the risks imposed to the system under intervention. The difficulty, risks and costs increase with water depth. In the Campos Basin, offshore Brazil, with around 500 subsea wells, in water depths range from shallow to ultra deep, leaks in hydraulic systems have a significant impact on maintenance costs. Sensitive components are down-hole safety valves, wet christmas trees valves, annulus subsurface safety valves and subsea manifolds subsystems. These aspects made the search for reliable remote or light workover solutions an important issue. A promising solution was introduced in Campos Basin in the year 2000, which makes use of a pressure-activated sealant fluid. This paper presents a case study comprised of tens of pressure-activated sealant applications, both in fixed and floating systems, carried out in Campos Basin in the last four years. The paper summarizes the operational programs, the field reports, the post-job analyses and the results achieved. The study revealed that pressure-activated sealants are a safe and economic method to repair leaks in offshore hydraulic systems. As the number of offshore oil and gas production systems, mainly the floating ones, tends to increase considerably in the near future, the knowledge acquired in Campos Basin may be useful worldwide. The main differential of this paper is a thorough and critical review, from the operator point of view, of 71 applications from 01/21/2000 to 05/16/2005.
Life Beneath the Platforms—The Movie …
Authors: Holyoak S. , Munns R. , Oldfield M.
Published: December 2007

Proposal

A supporting paper (Ref. 1) describes the results of the Platform Environmental Project, aimed at documenting and understanding the diverse ecosystem associated with the oil and gas production platforms, offshore Belait, Brunei Darussalam.

In order to demonstrate the development and diversity of the species present, a 20-minute documentary has been made. This captures the colour and dynamics of the marine life in a way that is not possible via written documentation alone. The DVD-based film is therefore seen as an excellent tool to increase the awareness of the platform ecosystem amongst stakeholders and other interested parties.

By showing this film at the conference we aim to highlight another angle of the environmental impact of the oil and gas industry, one that should be a key part of any future discussions regarding decommissioning options in the region.
Health, Safety and Environment Culture in the Norwegian Petroleum Industry
Authors: Høivik D.
Published: December 2007

During the last few years there has been increased focus on Health, Safety and Environment (HSE) Culture in the Petroleum industry in Norway. The concept of HSE culture can be understood in different ways and on different levels. This study concludes that a holistic, systemic way of understanding HSE culture gives an opportunity both for understanding and for taking appropriate actions for HSE.
Removing Mercury from the Workplace: A Case History of the Decommissioning and Recycling of Mercury-Contaminated Equipment
Authors: Berdugo V. , Bjoroy R. , Richards C. J. , MacWilliam D. , Riding M. , Ross B.
Published: December 2007

A project was undertaken by the company to locate, quantify, and remove all mercury-contaminated equipment and elemental mercury from its global network of field and laboratory operational locations. The equipment and elemental mercury was shipped to prequalified vendors for equipment decontamination, mercury recovery, and purification with the aim of recycling the recovered mercury and decontaminated materials back into use.
Malaria Control Measures for Oil and Gas Operations – What Works – What Doesn't – What Does the Literature Say?
Authors: Balge M. Z. , Krieger G. R.
Published: December 2007

Exploration and Production projects can potentially create adverse health impacts for workers and surrounding communities unless appropriate malaria control programs are designed, implemented and monitored on an ongoing basis. These company based control programs often contain measures that often are not evidence-based and that may actually impair community malaria control efforts.

This paper will present strategies and tools for use in developing effective malaria prevention and control programs through reviewing the current literature regarding: Malaria educationBite prevention and vector controlChemoprophylaxisDiagnosis and treatment

These strategies can result in cost effective mitigation of potential adverse health impacts by implementing scientifically based programs developed for the specific malaria risk in the defined geographic area.
Environmental Management for Thai Offshore Base Construction Project
Authors: Lambasara D. , Soponkanabhorn T.
Published: December 2007

PTTEP's Thai Offshore Base (TOB) has been under construction since 2002. Several potential environmental impacts include fish farming, ground vibration, potential shoreline erosions and excessive noises were encountered. To this, PTTEP took new initiatives in implementing series of environmental management into the project in order to solve any profound impacts to environment claimed to have occurred and to the nearby communities. PTTEP had set up a so-called Environmental Impact Monitoring Committee chaired by Sonkhla Provincial Deputy Governor which was comprised of representatives from provincial governments and local agencies, representatives from the local residents in community and the project owner to continuously observe changes and any environmental impacts occurred. The Environmental Impact Monitoring Committee meetings were held on regular basis to solve any problems resulted from the project. Moreover, series of other environmental management initiatives were also implemented throughout the construction period such as the use of silt curtains. PTTEP installed the silt curtains around the dredging sites to prevent outflow of silts. It was the first large and systematic silt curtains ever installed in Thailand for dredging sites. Series of other environmental management works were implemented such as routine and regular environmental quality monitoring of seawater, air, noise, etc, and conducting a PostEnvironmental Impact Assessment (EIA) for any changes in designs which occurred.

PTTEP's environmental management initiatives on TOB project has proved to be efficiently implemented without any major protests, unlike other projects during that time. Experiences gained from this project have been successfully applied to other project such as the major gas pipeline in the southern Thailand.
An Evaluation of Well Completion Impacts on the Performance of Horizontal and Multilateral Wells
Authors: Ouyang L. -B. , Huang B.
Published: December 2007

Well completion plays a critical role in well design, and more importantly, the performance of the well in its entire life. The major objective for this study is to provide some guidance in the design of completion configuration by a series of simulation with different completions under different flow and reservoir environments. The reservoir inflow and the wellbore hydraulics under complex completion environment will be fully coupled in the study. The most popular completion options, including open hole, slotted liner, inflow control devices (ICD), intelligent well completions (DIACS), perforated cemented liner, wire wrapped screen, ECPs, gravel pack, and frac pack, will first be briefly introduced and reviewed. The performance of the completions will be explored and compared for different wells under different flow conditions, including fluid type, well type, well rate, pressure drawdown, and reservoir geology.

Well performance will then be studied in details by evaluating the total well production, annular flow and flow inside the liner/tubing, pressure profiles along the annulus and along the liner, inflow from reservoir to annulus and fluid transfer between annulus and liner, and so on. Impacts of key parameters like skin factor, wellbore length, well completion configuration, and pressure drawdown, will be investigated.
Implementation of Slurry Fracture Injection Technology for E&P Wastes at Duri Oilfield
Authors: Arfie M. , Marika E. , Purbodiningrat E. S. , Woodard H. A.
Published: December 2007

The Duri oilfield is one of the 141 oil fields operated in Sumatra, Indonesia by PT Caltex Pacific Indonesia under a production sharing contract with the Government of Indonesia. Discovered in 1941, the Duri field is one of the world's giant oilfields and the biggest steamflood operation located in the Rokan block with current oil production of 200,000 bpd (31,000 m3 per day). The insitu formations of the Duri field are unconsolidated sands; coupled with a steam flood operation they are susceptible to producing large quantities of oily viscous fluids as a by-product from the oil production. Up to 400 m3/day (2,500 bpd) of oily viscous fluids are generated at five oil production Central Gathering Stations (CGS) in the Duri oilfield.

Slurry Fracture Injection™ (SFI™) is an environmentally viable deep well disposal process for Exploration and Production (E&P) waste streams. The SFI process can be used in the petroleum industry to dispose of produced solids, oily viscous fluids/sludges, tank bottoms, contaminated soils and drill cuttings.

There are a number of environmental advantages associated with the SFI process that make it suitable for E&P waste management strategies that include: permanent disposal of waste materials, zero surface discharge, no adverse interaction with the environment, reduced risk of ground water contamination, and relatively low cost. The SFI process was determined to be the most environmentally viable process for E&P waste management at the Duri oilfield in Sumatra. This SFI project represents the first time that the SFI process was implemented in Indonesia. This paper details the SFI project assessment, development, and field operations related to this deep well disposal process at Duri.
The Use of Nonintrusive Ultrasonic Intelligent Sensors for Corrosion and Erosion Monitoring
Authors: Instanes G. , Lakshminarayan B. , Toppe M. , Nagy P. B.
Published: December 2007

Corrosion and erosion detection and monitoring are essential prognostic means of preserving material integrity and reducing the life-cycle cost of industrial infrastructure, ships, aircraft, ground vehicles, pipelines, oil installations, etc. Spatially dynamic pipeline monitoring systems have to necessarily face extremely hostile conditions of operation including surface roughness, fluid loading issues, temperature variations, and a host of other factors that make development of a robust wall thickness assessment tool a challenging task. This paper describes the working of ClampOn's Corrosion-Erosion Monitor (CEM) - an online, real-time path based thickness assessment tool that deploys a set of transducers over a given pipe area, and utilizes a combination of resonance and dispersion based principles to assess wall thickness loss. This instrument was developed keeping the needs of the oil, gas and petrochemical industry in mind, both upstream and downstream, but because it essentially monitors reductions in wall loss, it can find applications in many other industries. Experimental and analytical work in- house provide very promising results pertaining to the functionality of the CEM system, and some of these results have been discussed in this paper. The CEM is a permanent installation on the outer pipe wall to produce real-time pipe wall thickness information, not as a spot measurement, but as a unique average path wall thickness. This state-of-the-art technology is extremely versatile, and can serve as a particle and sand monitor as well.
Black Oil Delumping
Authors: Ghorayeb K. , Holmes J.
Published: December 2007

Black oil reservoir simulation still has wide application in the petroleum industry, because it is computationally far less demanding than compositional simulation. But a principal limitation of black oil reservoir simulation is that it does not provide detailed compositional information necessary for surface process modeling.

Black oil delumping overcomes this limitation by converting a black oil wellstream into a compositional wellstream, enabling the composition and component molar rates of a production well in a black oil reservoir simulation to be reconstituted.

We present a comprehensive black oil delumping method based primarily on the compositional information generated in the depletion process that is used initially to provide data for the black oil simulation in a typical workflow. Examples presented in this paper show the accuracy of this method in different depletion processes: natural depletion, water injection, and gas injection. The paper also presents a technique for accurately applying the black oil delumping method to wells encountering crossflow.
Successful Drilling of Basalt in a West of Shetland Deepwater Discovery
Authors: Close F. , Conroy D. , Greig A. , Morin A. , Flint G. , Seale R.
Published: December 2007

Drilling in deepwater is very expensive, with rig rates in the hundreds of thousands of dollars per day and high spread costs. When coupled with drilling exploration wells in areas with unknown and "difficult" formations, the risks escalate exponentially.

An example of this is the recent drilling on the ChevronTexaco Upstream Europe discovery well in the West of Shetland province of the UKCS. On this particular wildcat exploration well the potential of encountering a volcanic/basalt sequence had been highlighted at the planning phase. Only limited offset data was available, the closest offset well being some 15 miles (24km) from the proposed well location. A general overview of the well and its objectives is given. The paper focuses on the original drilling philosophy and why it changed during the drilling of the well and the reasons which ultimately led to the use of a turbine and diamond impregnated bit. Factors in the successful drilling of the above well including lessons learnt will be explained. The trade-offs with the various BHA configurations and the impact on data acquisition is also explained.

The paper also consolidates the offset information and some of the research and development of basalt drilling at high speeds using turbines. The paper therefore outlines the equipment run in the extensive volcanic/basalt section and the establishing of new benchmarks for the drilling of this extremely challenging formation in a deepwater and high cost environment.
Experimental Investigation of Wellbore Phase Redistribution Effects on Pressure-Transient Data
Authors: Ali A. M. , Falcone G. , Hewitt G. F. , Bozorgzadeh M. , Gringarten A. C.
Published: December 2007

Pressure transient analysis is a well established reservoir evaluation method. By analysing pressure and pressure derivative curves from build-up and drawdown tests, it is possible to identify reservoir characteristic parameters and heterogeneities. However, much of the pressure data recorded during a well test may be dominated by wellbore effects that can mask reservoir characteristics and lead to erroneous well test interpretations. This is particularly true when the well production rate is controlled at surface and more than one phase is flowing. These effects, which are transient in nature, include phase change, flow reversal, and re-entry of the denser phase into the producing zone.

This paper presents the results of experiments carried out at Imperial College to investigate the effects of phase redistribution and phase re-injection on pressure build-up data. Single-phase and two-phase flow tests were conducted with air and water. An experimental rig was designed to emulate a reservoir connected, via a resistance, to the base of a flowing well. The "reservoir" is recreated by a pressurised vessel, while the "well" is simulated by a vertical pipe. The "well" was flowed at controlled rates to mimic those encountered in gas condensate reservoirs. After steady-state conditions had been attained, the "well" was shut-in at the top of the rig (i.e. at surface) and the associated transient phenomena monitored via distributed measurements of pressure, temperature, liquid hold-up and wall shear stress. Pressure build-up data were interpreted using established well test analysis techniques.

The experiments provide a qualitative and quantitative understanding of the effects of gas rates, liquid rates and rising gas bubbles on wellbore phase redistribution and re-injection. The results yield an insight into the corresponding impact on well test transient pressure behaviour.