bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Evaluation Through Extended Well Testing-Moran Field, PNG
Authors: Wali K.F. , Bantz D.M. , Pedersen K.N. , Karaman O.S. 
Published: December 2007

Abstract
An extended well test (EWT) is currently being conducted in Papua New Guinea(PNG) in the recently discovered Moran Field. The objective of this EWT is to evaluate reservoir volume, deliverability, recoverable oil and communication within major fault blocks. This information is being integrated with other reservoir data acquired during field delineation for optimising full-field development of this geologically complex field.

Introduction
The Moran field, located in the Southern Highlands Province of Papua New Guinea, was discovered in September, 1996, in the same production license (PDL2) as the presently producing Kutubu fields. Oil was found in the same two separate intervals, the Toro and Digimu sands, that presently produce at Kutubu. Initial well test rates were over 8,000 barrels per day of high-gravity, sweet oil from each interval. A follow-up delineation well discovered an additional reservoir and extended the oil column height over 4000feet in two major fault blocks.
Design Optimisation of Laminaria/Corallina Fields Subsea Facilities
Authors: Smith N.T.G. , Hamp R. , Maloney M. 
Published: December 2007

Abstract
Woodside Offshore Petroleum, together with joint venture participants Shell Development Australia and BHP Petroleum, are developing the Laminaria and Corallina Fields in the Timor Sea. The selected development concept is a floating monohull production facility supplied by subsea wells. This paper describes the approach taken by the Project team to deliver a diverless deepwater subsea facility which met the objectives of flexibility and maximised value whilst accommodating the evolving subsurface modelling process. A key element of the approach selected was the philosophy of Best Managed Risk (BMR), and the application of this philosophy to deal with reservoir uncertainties during the subsea design process is discussed. A second key element was the early definition of a "minimum facilities field layout" to which additional facilities could only be added if justified by a rigorous business case which demonstrated added value to the Project. The benefits of this strategy in allowing capital expenditure to be controlled in the face of significant uncertainties is discussed and supported by several examples.
P. 327
A Strategic Approach to Designing FPSO Vessel Power Generation Systems
Authors: Colton Jonathan S. , Low Yee Weng 
Published: December 2007

Abstract
A design process is proposed as a strategic approach for designing FPSO vessels power generation systems. The design process is formulated based on analyses of both offshore- based and land-based power generation system design issues, and with the belief that the design process is both effective and efficient if it treats as many of the relevant economic and project engineering issues as possible. A design process framework and a power generation systems design problem are described and discussed.
P. 339
Fast Connector for Drill-Pipes
Authors: Kamp G.P. , Bakker T.W. , Smith J.E. , Young T.F. 
Published: December 2007

Abstract
With the increasing focus on creating possibilities to economically develop marginal fields, the basic rotary drilling concepts are being reviewed to reduce the costs of drilling wells. This paper presents a preliminary design of a Fast Connector, which reduces the make-up time, while the mechanical performance is comparable to that of conventional tool-joints. The geometry of this specific connection provides even some extra features, which are not possible with conventional tool-joints.
P. 351
Laboratory Testing and Field Implementation of Scale Inhibitor Squeeze Treatments to Subsea and Platform Horizontal Wells, North Sea Basin
Authors: Jordan M. M. , Tomlinson C. J. , Pritchard A. R. P. , Lewis M. 
Published: December 2007

Abstract
This paper presents field results from a number of scale squeeze treatments carried out on subsea and platform horizontal wells from a field in the North Sea (Nelson field). The evaluation of scale inhibitor chemicals from initial laboratory screening is reviewed along with significant factors which influence inhibitor selection when designing squeeze treatments for both horizontal and highly deviated wells. This includes discussion of formation brine/inhibitor incompatibility and formation minerals/inhibitor incompatibility. The potential for sand production and oil-in-water process upset which can result from the above factors is also discussed.
This paper outlines the practical difficulties in squeezing subsea horizontal wells and how some of these problems can be overcome. Some of the practical solutions discussed include the use of chemical stabiliser to reduce formation brine/inhibitor incompatibility, variation of pump rates to encourage propagation of inhibitor along the wellbore and the potential of fluid diversion (both mechanical and chemical). The significance of production logging data or good reservoir simulation data, to evaluate the location of water production prior to a squeeze treatment, is also stressed. This paper also presents details of divertor selection and the resulting squeeze design strategies that may be implemented.
From this series of field squeeze treatments it can be concluded that the wells have all been successfully treated, with minimal process upset during flowback, as a result of continuous design improvement based on the previous treatments. No long term decline in well productivity was observed as a result of these treatments. This paper clearly shows that with the correct laboratory evaluation process for both scale inhibitor and divertor agents and with utilisation of production logging and reservoir simulation data, it is possible to squeeze scale inhibitors into platform and subsea horizontal wells without the need for coiled tubing intervention.
Results of a Field Test to Improve Hydraulic Blowout Control Calculations
Authors: Oudeman P. , Mason D. 
Published: December 2007

Abstract
In the offshore environment, options to regain control over a blownout oil or gas well directly from surface, e.g. by capping are limited, particularly in the case of subsea wells or underground blowouts. Hence injection of a kill fluid via a relief well will often be the only alternative. In view of offshore logistics and cost of such an operation, this requires reliable estimates for the kill rate, pump pressure, hydraulic horsepower, kill fluid density and volume, prior to spudding relief well(s) and arranging for the pump equipment, fluid make-up plants and storage capacity. Various methods to estimate these parameters have been proposed. Validation of the methods has been very limited however since an actual blowout situation, with all inherent uncertainties (e.g. with respect to blowout well performance) does usually not allow a thorough kill job evaluation. To close this gap between theory and practise, a dedicated full scale field test to study how a dynamic well kill proceeds in a high rate gas well, has been designed, executed and analysed. Through variation of the blowout and kill rates, conditions under which the well ceased flowing could be determined accurately. Valuable insights on the processes taking place in the well during the kill were obtained. Analysis of the test results shows the correct methodology to predict the parameters for a successful and efficient kill job.
P. 103
Multiple Proppant Fracturing of Horizontal Wellbores in a Chalk Formation: Evolving the Process in the Valhall Field
Authors: Norris M.R. , Berntsen B.A. , Skartveit L. , Teesdale C. 
Published: December 2007

Abstract
Oil production from this chalk field has been improved significantly over the last three years through the use of multiple proppant fractures placed from horizontal completions. Following early successes the engineering effort now focuses on increasing value through engineering innovation and increased productivity. This paper describes, through case histories and field data, the advances made in the design and execution of these completions over the first 13 such wells in the field.
Wellbore completion activities and stimulation are now performed as a standalone process through the use of specialized large diameter coil tubing equipment so allowing on-going drilling operations to be performed concurrently. This has significantly reduced daily spread costs while bringing wells on production within a much reduced time frame. This lower cost environment has also allowed innovative field procedures to be developed resulting in further improvements such as proppant plugs for isolation between stimulation zones and treatments using recycled proppant to minimize waste.
Treatment design has been refined through downhole pressure monitoring which has allowed empirical frictional relationships to be developed for proppant slurry and coil tubing circulating fluids. This data validates the wellbore tubulars design and allows any weak points in the arrangement to be highlighted for change. An extensive fracturing database is maintained allowing each treatment design to be compared with previous experience in the field.
Productivity is the driver for economic success and treatment design requirements have evolved through laboratory testing to account for longer term downhole operating conditions below the bubble point while also improving initial conductivity. Field data to date through PLT logging has confirmed the hydrocarbon contribution from each fracture and this is used to validate, or otherwise, the effectiveness of each treatment. Normalized well productivities continue to improve and the challenge is to maintain the rate of evolution through the improved application of both new and existing technologies.
P. 335
Emulsified Acid Enhances Well Production in High-Temperature Carbonate Formations
Authors: Navarrete R.C. , Holms B.A. , McConnell S.B. , Linton D.E. 
Published: December 2007

Abstract
Emulsified acids were traditionally used in acid fracturing, and more recently on matrix treatments of carbonate formations. The delayed nature of emulsified acids is useful in generating longer etched fractures or deeper wormholes. Emulsified acids also have higher viscosities than straight acid, which reduces fluid loss in acid fracturing applications and helps distribute acid more uniformly in formations with high-permeability contrast during matrix treatments. A new emulsified acid system is presented in this paper that is stable up to 350 F, highly retarded, and significantly more viscous than straight acid. Laboratory data comparing emulsified acid with straight acid are presented at temperatures ranging up to 350 F, including rheology and acid conductivity. Field case histories in the Smackover formation in Alabama over two years are presented. The field case histories show the improvements in production of oil and gas resulting from emulsified acid fracturing treatments in comparison with prior similar treatments done with straight acid.
P. 391
New Technology, Invert Emulsion Scale Inhibitor Squeeze Design
Authors: Lawless T. A. , Smith R. N. 
Published: December 2007

Abstract
Normal squeeze injection strategies employ inhibitor based formulations and brine overflushes to penetrate radial distances of ~12 feet. However, as a direct result of this strategy, oil continuity between pore spaces in the near well bore area is lost, leaving discontinuous oil droplets resident in the pore spaces. Relative permeability effects dictate that following shut-in, water production will be favoured, whilst oil will have to overcome physical barriers before oil continuity, between pore spaces, to the well bore location can be achieved. As such, the major costs associated with squeeze exercises are those incurred as a direct result of deferred oil production, arising from failure to return to pre-squeeze oil productivity for periods between 3 and 21 days.
The ability to utilise invert emulsion technology (brine dispersed in kerosene) with the aqueous phase containing a scale inhibitor in solution is presented as an attractive alternative. The proposed technology will combat current deficiencies and deliver a new approach to the process of scale control. It is important for squeeze operations, however, that the emulsion can be injected safely downhole and encouraged to "break" during shut-in, thus allowing the aqueous inhibitor to be released and contact the rock structure, promoting effective retention. The "broken" oil phase maintains continuity between pore spaces and promotes rapid oil productivity to return, post-squeeze, as a result of relative permeability effects. Economic benefits are identified and detailed considerations relating to the appropriate physicochemical and environmental characteristics of target emulsions are presented. Experimental and theoretical evaluation exercises on promising emulsion formulations for field applications are presented and reviewed.
Emulsion compositional requirements for successful field applications have been systematically addressed using phase mapping routines to establish preferred candidate selection. The method of emulsion manufacture, its phase volume composition, destabilisation route and resulting rheological characteristics are described along with the development of a model to describe fluid viscosity over a range of likely field conditions. Compatibility with selected field stock tank oils and formation waters are reported over a range of mixing ratios to establish application potential. Coreflood routines, conducted at 90°C, using a conventional squeeze approach as well as a formulated, controlled breakage, invert emulsion system are presented. Both squeeze treatments reveal equivalent inhibitor return characteristics, but post-squeeze oil production for the emulsion system shows inherent benefits.
Drill-In Fluid Filter-Cake Behavior During the Gravel-Packing of Horizontal Intervals — A Laboratory Simulation
Authors: Becker Thomas E. , Gardiner Nicholas H. 
Published: December 2007

Abstract
A simulated horizontal well section allows studies regarding the buildup and removal of drilling-fluid filter cake. For the study described in this paper, researchers used the well section to examine the effects and behavior of drill-in fluids before, during, and after gravel packing. Specifically, the following conditions were examined: (1) filter-cake thickness, (2) filter-cake permeability, (3) local permeability variations behind the sand face, and (4) the effects of sand scouring on the preceeding three quantities during gravel packing.
The 6-ft long test apparatus resembles a linear section of casing-and-borehole annular space where differential pressure can cause drilling-fluid filter cake to develop. Temperatures in the apparatus can be increased, as needed, up to approximately 200°F, and fluid is flowed axially through the rectangular flow channel. The special design of one channel wall, which consists of permeable, unconsolidated sand, supported by screen, allows filter cake to build up. The fluid is flowed through the channel until the cake-building pressure is balanced by the flow's erosive forces.
The drill-in fluid temporarily plugs the sandstone face, allowing the axial flow to carry the gravel-packing sand throughout the length of the horizontal section. Laboratory tests with this apparatus showed that a properly selected drill-in fluid can plug a high-permeability sand within seconds after contact, and reduce permeability a 1,000-fold. This low permeability can be maintained throughout the sand-pumping process, even when the filter cake is almost completely eroded.
To date, this plugging procedure has been used successfully on multiple horizontal wells with a typical horizontal-section length of 1,000 to 2,500 ft, and plans are underway for it to be used on more wells. Laboratory test results closely agree with the results observed in these field wells.
A Stimulation Treatment of a Sub Sea Well Using a Scale Dissolver
Authors: Børeng Raymond , Bakken Knut Olav , Vikane Olav , Angelsen Atle 
Published: December 2007

Abstract
The Stattjord East and North are two sub sea fields tied in to the Stattjord C platform on the Stattjord Field. A well, on the Stattjord East satellite was damaged during the gravel pack operation. The damage is believed to be rust particles due to use of dirty drill collars during placement of the pre pack gravel. The productivity index, PI, of the well after clean up of the perforations, i.e. prior to gravel packing, was calculated as 742 Sm3/d/bar. After gravel packing and bean up of the well, the PI was calculated as 55 Sm3/d/bar. The well observed increased productivity to about 80 Sm3/d/bar before its decline prompted the use of a scale dissolver to remove the damage. The challenge was to pump the scale dissolver 7.8 km from the platform out to the wellhead template through a 2.5 inch methanol line. At the time of performing the stimulation treatment the oil rate of the well was 776 Sm3/d with a PI of 11 Sm3/d/bar. The maximum pumping rate during the operation was 800 litres per minute. After the scale dissolver had been soaked in the gravel pack for 12 hours, the well was put on production and it delivered 2600 Sm3/d of oil. The PI was increased to 55 Sm3/d/bar. A decline in production was observed, and after a year a second squeeze was performed successfully. The PI increased this time from 23 to 59 Sm3/d/bar and the oil production increased with 1000 Sm3/d. For the first time in the Norwegian North Sea, successful stimulation treatments of a sub sea satellite well has been achieved by pumping a scale dissolver through a 2.5″ methanol line into a 5.5″ completed well.
The evaluation of the data has shown that the plugging process is complex and difficult to interpret. However, it can be concluded that injection of fluids has improved the gravel pack productivity. The erosion potential has also been minimised due to reduced draw down across the gravel pack.
The damage mechanism is most likely a combination of rust, brine and fines plugging the wire wrapped screens and the poorly filled perforation tunnels.
The first stimulation operation had a payback time of 2 days and the second operation 4 days.
Rapid Risk Ranking for Field Development Optimisation to Achieve ALARP
Authors: Burch M. E. , Goddard J. 
Published: December 2007

Abstract
The recent changes in Safety Legislation and Guidelines away from prescriptive requirements are becoming increasingly well known and understood. However, the tools and processes for managing risk are not keeping pace with these changes. With this broader scope to optimise risk, the top performing companies and their managers demand answers to ever more challenging questions, testing the capabilities of safety and risk professionals. This is never more so than during the engineering phase of new projects where timely, correct decisions are essential – particularly when personnel safety, asset protection and project economics (cost, revenue and schedule) are some of the main decision criteria.
One of the goals of effective risk management is to ensure that risks have been reduced to as low as reasonably practicable (ALARP). Managing risks at the earliest stage of a project to ALARP will result in achieving an inherently safe development with an associated maximisation of Net Present Value (NPV).
In order to meet these objectives, risk and safety professionals need tools to support engineering. These tools must perform quantitative cost benefit trade-offs efficiently and effectively.
This paper explains the nature of these challenges and decisions, together with a methodology and tools which manage risk (while maximising NPV) and assist in the decision making process.
Wireline Tractor Production Logging Experience in Australian Horizontal Wells
Authors: Local Eddiexz , Searight Thomas L. 
Published: December 2007

Abstract
New wireline tractor technology has been developed and used successfully in Australia to deploy production logging tools in horizontal wells. The results of operations in the Wandoo field in Australia are presented. The dynamics of tractor operations have been modelled, and field data has been used to validate the model and to quantify borehole friction coefficients. The model may be used to assist job planning and to assess the feasibility of deployment by wireline tractors in general situations.
Practical Solutions to Combat the Detrimental Effects of Hydrogen Sulfide During Drilling Operations
Authors: Carney Leroy L. , Jones Bob 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
This paper includes a history of the efforts which have been put forth to minimize or eliminate the various problems caused by hydrogen sulfide.
When hydrogen sulfide enters the borehole during drilling, completion, or testing for hydrocarbons, it creates several very detrimental problems. These problems are encountered regardless of the source of the hydrogen sulfide.
Hydrogen sulfide can be dangerous to personnel on the surface, can cause cracking personnel on the surface, can cause cracking of drill pipe and tubular goods, and destruction of testing tools and wire lines.
Less severe problems, however still important to good drilling practices, are incompatibility of hydrogen sulfide and drilling fluids and obscurement of test results for other ions contained in drilling fluids filtrates which are important to successful drilling practices.
The advantages and disadvantages of using the following compounds for scavenging hydrogen sulfide from water base drilling fluids are compared.Copper CompoundsZinc CompoundsIron CompoundsHydrogen PeroxideChelates
The use of oil base drilling fluids instead of water base fluids for drilling has certain advantages in areas where hydrogen sulfide is likely to be encountered.
Designing special invert emulsion base fluids for use in completion and drill stem testing is suggested and the chemistry of these specially designed fluids is explained.
Testing for the presence of hydrogen sulfide in drilling fluids is discussed.
Many of the efforts that have been reported by service companies and oil companies for combating hydrogen sulfide during drilling operations are summarized.