bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of PVT Data Quality on Hydrocarbon Recovery Predictions
Authors: Trengove R. D. , Hann J. H. , Skates J. R. 
Published: December 2007

Abstract
The effect of PVT data quality on simulator estimation of liquid hydrocarbon recoveries under various gas sales scenarios was investigated. An extended black oil reservoir simulation model together with the fluid model from the Third SPE Comparative Solution Project1 and a gas condensate fluid from Drohm et al2 were used.
Experimental constant volume depletion (CVD) liquid saturations were modified by the method of Drohm et al2. The unmodified and modified gas condensate data sets were used to generate equation of state (EOS) characterisations and black oil PVT tables for input to reservoir simulation.
The EOS characterisations were constrained to reproduce the liquid saturations. For the modified data it was possible to match both the observed dew point and the modified liquid saturations. However, the EOS characterisation which was matched to the raw liquid saturations underpredicted the experimentally measured dewpoint.
The applicability of the black oil simulation model is discussed and various scenarios are compared to show the influence of data corrections on simulation results.
Completion Design For Corrosive Well Conditions
Authors: Callihan R.B. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
In certain producing fields in the United States, Canada and other countries with severe corrosive conditions, special downhole equipment installations have been developed to meet the requirements of production and stimulation. This paper classifies corrosive well conditions and associated theoretical considerations, and describes packer and tubing equipment being successfully used for these conditions. Certain guide lines are established for designing completions for a wide range of corrosive conditions in producing wells.

Introduction
Throughout the producing areas of the world, a variety of special equipment is employed to combat corrosive well conditions. The design of special packers and tubing strings is dictated by the nature and severity of the corrosive environment in addition to the normal requirements of production or injection.
Corrosive environments consist primarily of produced fluids containing varying amounts of H2S produced fluids containing varying amounts of H2S and CO2 at a wide range of pressures and temperatures. Even so, there Is enough similarity of downhole conditions, such that, classification of successful equipment installations has been very helpful in designing equipment for other corrosive areas.
So many corrosive producing formations require stimulation by acidizing or fracturing to improve production. Rig time can be saved by equipping the well to stimulate after initial completion. Special equipment has been developed to permit tubing expansion during stimulation and accommodate inhibitor injection while on production. production.

TYPES OF CORROSIVE WELL CONDITIONS
Corrosive conditions in producing wells can usually be described as sour or sweet corrosion. Sour corrosion is due to hydrogen sulfide in production, while sweet corrosion is primarily a production, while sweet corrosion is primarily a result of carbon dioxide in produced fluids.

H2S Conditions
In the presence of moisture, H2S in production can result in iron sulfide corrosion and hydrogen stress cracking. Iron sulfide is a general corrosion which appears as a black powder or scale on exposed steel surfaces. Hydrogen stress cracking is a failure of high strength steels due to hydrogen embrittlement which can occur without visible corrosion damage. It has been found that only a trace of hydrogen sulfide is necessary to cause hydrogen stress cracking.

CO2 Conditions
When CO2 and water are present in production, a resulting acid condition may cause iron carbonate corrosion. Damage to well equipment normally takes the form of deep pitting where corrosion-erosion occurs.
Horizontal Well Completion Recommendations Through Optimized Formation Evaluation
Authors: Ahmed U. 
Published: December 2007

Abstract
Use of horizontal well completion to enhance hydrocarbon recovery has increased considerably in the past several years. Projections for future horizontal wells hold considerable promise as long as well productivity enhancement outweighs the incremental cost. The success of horizontal wells to date appears to be related to the development and application of specific technology. Optimized completion techniques are on top of the list of such required technology. Recent publications clearly demonstrate that without proper formation evaluation, adequate completion is typically unachievable and often results in premature well abandonment.
This paper targets the three most common horizontal well formations subject to completion: naturally fractured, matrix permeability dominated systems and formations bounded by a gas cap or an aquifer or both. The formation parameters that best define matrix permeability dominated systems are quite different than those associated with naturally fractured formations. The paper first identifies the parameters that best define individual formations. Possible completion options for these formations are then discussed.
Optimized completion recommendations are presented for each of the formations through use of case studies. Recommended completion procedures for naturally fractured formations require use of external casing packers and alternating perforated or slotted and blank pipes. Zonal isolation is of prime importance in matrix permeability dominated systems, especially when the pay interval is bounded by a gas cap or an aquifer or both. The recommended completion procedure for these types of formations uses cemented casing and selective perforating.
Development of Oilfield Facilities on a Nature Reserve: The Airlie Island Experience (Onslow, Western Australia)
Authors: Long P. J. , Long V. L. 
Published: December 2007

Abstract
Airlie Island is a small (26 hectare) sand cay, located 35km north of Onslow in Western Australia. In common with other islands in the region, Airlie is a nesting site for seabirds and turtles, but its two primary conservation resources are the large Wedge-tailed Shearwater rookery which covers 64% of the island and an endemic skink species. Its conservation values have prompted the Western Australian State Government to declare the entire island a nature reserve set apart for the preservation of flora and fauna.
In 1987 Western Mining Corporation Pty Ltd developed the South Pepper and North Herald oilfields and part of this development included the siting of an oil terminal on Airlie Island.
It may be expected that the conservation resources of the island and the Company's requirements for land would be incompatible. However, a careful study of the local environment and the creation of a detailed plan to manage this environment resulted in an acceptable compromise. The vegetated area of Airlie Island was reduced by 3.1 hectares, or 12%, and appropriate siting and design of the facility minimized the impact on wildlife. Disciplined execution of the management plan during construction was an essential part of the overall environmental success of the project.
This case study shows that conservation and exploitation can be compatible if appropriate management strategies are developed and strictly implemented.
Planning and Drilling Australia's First Medium-Radius Horizontal Wells
Authors: Moo T. J. , Tweedy M. W. 
Published: December 2007

Abstract
During early 1991 West Australian Petroleum Pty. Limited acting as joint venture operator for Chevron Asiatic Limited, Texaco Oil Development Company, Shell Development (Australia) Pty. Limited, Ampol Exploration Limited and Western Mining Corporation Limited successfully drilled the first two medium radius wells in Australia.
The two wells G88B and Cowle No.2 were very different in many aspects.
The first well G88B achieved a 500m horizontal well bore at 615m true vertical depth (TVD) using build up rates to horizontal in excess of 10 degrees/30m(5.818E-03rad/m). The well was drilled onshore using a relatively small drilling rig with minimal additional equipment.
The Cowle No.2 well achieved a 1002m horizontal well bore at 1098mTVD using a build up rate of 9 degrees/30m(5.236E-03rad/m). This offshore well utilized a significantly higher capacity/capability drilling rig than that used on the G88B well.
Both wells were able to be horizontal within 240m of their surface locations representing a significant decrease in horizontal and vertical displacement required to build to horizontal.
Horizontal wells drilled within Australia had previously utilised long radius builds which require greater horizontal and vertical distances before reaching horizontal, longer well paths and generally longer drilling times1.
The success of the first two medium radius build to horizontal wells in Australia confirms that horizontal sections can be accurately drilled with shorter horizontal displacements and vertical sections than previously thought possible. The practicality of drilling shallow horizontal wells onshore using available drilling rigs is also confirmed.
Drilling Extended-Reach Wells, Northwest Shelf, Australia
Authors: Scott P. W. , Lintern G. A. , Embury J. E. 
Published: December 2007

Abstract
Woodside Offshore Petroleum has taken advantage of state of the art drilling technology to construct extended reach wells from fixed platforms to access more distant sections of reservoir. Well design has been optimised to reduce friction forces; strength and power of rig equipment and tools have been increased to handle higher design loads; drilling techniques have been adopted or developed which allow better control of the drilling process; and training has been used to prepare personnel for the changes, enhancing safety and efficiency.
The changes made to one platform were constrained by existing rig design making compromises necessary. The other rig was purpose designed to drill extended reach wells and is presently under construction. Its capability will be significantly greater.
Drilling and completion times on extended reach wells drilled to date have been shortened, thereby lowering well costs.
Contribution of Maintenance to the Safeguarding of Technical Integrity
Authors: Officer W. S. 
Published: December 2007

Abstract
The exploration and production upstream sector has adjusted to the oil price collapse of 1986 and has entered the new decade with a rationalised and restructured business portfolio. There has been a considerable drive to reduce cost and consolidate the business around the core activities, with increasing emphasis being placed on the maintenance contribution to the business objectives.
The prime role of maintenance is accountability for management of the safeguarding of technical integrity, and ensuring the required long term facility availability at optimum cash flow.
The oil industry entered the new decade having gained valuable lessons from the turbulent experiences of the later 80s period, demonstrating an ability to adapt and be sensitive to the need to "manage change"
There is now a growing realisation that a number of issues need to be addressed, in order to safeguard the long term technical integrity of assets.
This activity is made the more challenging by the number of facilities approaching design half-life, and the ever changing demands in production profile necessary to gain further commercial advantage.
Recirculation Method Using a Bottomhole Choke To Prevent Intermittent Production and Prolong Pump Life in Wells Lifted With the Electric Submergible Pump
Authors: Damsuki M. , Wahyudin P. 
Published: December 2007

ABSTRACT
The recirculation method using a bottom hole choke to prevent intermittent production and prolong pump life in wells lifted with the Electric Submergible Pumps (ESPs) is a new technique that was developed in ARCO offshore North West Java Sea Contract Area.
In some of the new fields developed by ARCO, accurate well productivity data was not available at the time that ESP sizing operations were conducted. This limitation resulted in some wells having ESPs that were oversized in-comparison to the well's inflow liquid capacity.
This situation is undesirable in that the well intermits and causes the pump to operate outside its designed operating range. Pumps which operate out of the recommended range for a prolonged period of time will have a short run life in comparison to one that is properly sized.
In order to circumvent the problem either one of the following three options is available to the engineer.: Allow the oversized pump to run until failure (if possible) at which point the ESP is extracted from the well.Use the variable speed drive by reducing the frequency to get lower production rate.Install a down hole choke to allow recirculation of well-bore fluids so the ESP well does not pump off. (i.e. the well does not intermit).
The last option has been pioneered in the ONWJ Contract Area and has saved a considerable amount of expense since the installation of a dowhhole choke only requires a slick line unit which is more cost effective than a work over or snubbing rig as option (1) above would require. Additionally, the use of the downhole choke has increased the average pump run life considerably field wide.
Snorre Subsea Tree and Completion Equipment
Authors: Williams J. D. , Ytreland S. 
Published: December 2007

ABSTRACT
The Snorre Subsea Production System (SPS) is an innovative 10 + 10 well facility which will be tied back to the Snorre tension leg platform (Figure 1). The Snorre SPS (Figure 2) will be installed in 1100 ft (335 m) of water, 93 miles (150 km) off the west coast of Norway in the northern sector of the North Sea2. The SPS installation is scheduled for the spring of 1992, with drilling and completion of the first subsea well slated for the fall of 1992. In general, field-proven components have been used wherever possible, with new technology being extensively verified and tested prior to installation.
To the extent practical, the drilling and completion equipment designs also use field-proven components. These components have been combined in a unique manner to produce a safe and reliable system which: (1) employs guidelineless, remotely-operated techniques for deployment, installation, and retrieval of the various subsea modules, (2) provides through flow line (TFL) maintenance capability, (3) uses metal seals and welded constructions for connections on permanently-installed equipment, (4) minimizes the number of hydraulic functions on the subsea tree, and (5) has been specifically designed to enhance the safety of simultaneous drilling and production operations.
This paper explains the basic design features of the Snorre subsea tree and completion equipment. In addition, a brief description of the equipment is provided.
Tordis Field Development: Single Satellite Wells with Subsea Manifold Centre
Authors: Kloeve B. , Hestad E. 
Published: December 2007

ABSTRACT
The planned Tordis development consists of seven individual subsea wells connected to a subsea manifold, tied back to Gullfaks C for processing of hydrocarbons, supply of injection water and Production control, (ref. Figure 1). Start is scheduled for 1994.
Gullfaks has agreed upon a receipt commitment of 12 000 Sm3/day of processed liquid capacity.
The subsea wells are successively drilled, completed and tied back to the manifold. This allows a high degree of flexibility in field development and defers expenditure.
This paper presents details of the system configuration, design, installation and operation, as of the issue date December 1990 of the Plan for Development and Operation.
Advancements in Field Installation of Preloaded Subsea Wellhead Systems for TLP and High-Fatigue Environments
Authors: Hines F. C. , Jennings C. E. 
Published: December 2007

ABSTRACT
This paper presents an overview of the evolution of design requirements for wellhead housing running tools necessitated by the development of wellhead interface systems to overcome the higher static and fatigue loadings generated by harsher environments and deeper water.
A brief history of the progression of wellhead designs is also presented in conjunction with their relevant running tools. A review of field operations for a new wellhead interface design with tapered sockets is presented along with the design of a tool that seats the double taper sockets [9].
Non-Linear Finite-Element Study of Pipeline Hot Tap Operations
Authors: Shanks J. M. , Wielenga W. M. H. 
Published: December 2007

ABSTRACT
To improve the reliability of large hot tap pipeline operations, Shell Expro commissioned a detailed non-linear Finite Element study to investigate the structural and mechanical response of such systems, in particular during pressure testing of the branch welds. The study included load steps simulating welding of branch to pipeline, hydrostatic pressure testing of the welds, coupon cutting and removal, and normal pipeline operation. A limit state analysis was used to determine the ultimate collapse load of the coupon during external hydrostatic pressure testing, and was verified by a small number of scale model tests and then used to complete a full parametric study covering all branch sizes and configurations of interest. In some cases the buckling pressure was found to be quite low and the effect of welding stiffeners to the coupon was quantified. Pipeline spring back deflections were also determined and assessed as to their effect on coupon cutting and removal operations. The results of the study were applied to a large hot tap connection on the FLAGS gas pipeline during the summer of 1990 and ensured a high level of safety at all stages of the operation.
Embla Field: Development of a Complex Reservoir Near Existing Infrastructure
Authors: Snow S. E. , Frey E. P. , Jewhurst J. , Kiesow U. G. , Knight I. A. 
Published: December 2007

Abstract
Embla Field is located within the Greater Ekofisk Area in the Norwegian sector of the southern North Sea, 5 km south of the Eldfisk Field. A well drilled in 1974 indicated the presence of hydrocarbons. The producibility of the reservoir was proved by a well drilled in 1988. An appraisal well drilled in 1989 confirmed the discovery. During tests, the field produced volatile oil from a thick, pre-Jurassic sandstone sequence at about 4200 m TVD. Reservoir pressure is 828 bar and reservoir temperature is 159°C. A three phase development plan for the field was proposed and approved in 1990.
Seismic definition of both the top of the reservoir and its internal geometry is poor. Log, core, and DST information indicate that the reservoir is geologically complex. In order to allow for geologic complexity, minimize economic risk and obtain the necessary information for optimum reservoir management, the first phase of the development will be a low cost wellhead platform which will take advantage of the existing infrastructure. Production from this phase will start in late 1992.
Phase I will consist of pre-drilling up to 6 wells in a step-out fashion, installation of a remotely monitored 18 slot platform and one year of special reservoir monitoring from the pre-drilled wells. The reservoir monitoring program is designed to establish reservoir continuity and production characteristics. The information obtained information obtained from the first phase will form the basis for the rest of the development.
Phase II will include infill drilling and development of the remainder of the field. Phase III will be a pressure maintenance/improved recovery program.
Several alternative development schemes, including conventional delineation of the reservoir or test production through a subsea completion, were considered. The selected alternative best addressed the uncertainties of Embla while taking advantage of the existing infrastructure.
A New Type Curve for Well Testing in Anisotropic Formations
Authors: Hayes M. R. L. , Vaughan A. B. 
Published: December 2007

ABSTRACT
It is recognised that depositional and tectonic processes can result in anisotropy in horizontal permeability. Previous authors have described inter well interference tests which can be used to determine the magnitude and direction of permeability anisotropy.
Earlougher describes the elliptical flow regime resulting from anisotropic permeability. He suggests that it is impossible to recognise anisotropy from a single well test as the pressure response curve is the same as for isotropic reservoirs. This is thought to be valid when the anisotropy occurs as a result of very small scale permeability variations.
The authors have observed that interpretations of welltests conducted on certain formations in the North Sea yield negative skins. The common feature of these formations is that they are prone to anisotropy.
This paper describes the flow regime resulting from large scale anisotropy. The reservoir modelled is assumed to contain a regular series of parallel partial baffles in an isotropic permeability field. Conventional radial flow is followed by an elliptical pseudo radial flow regime, akin to that described by Earlougher. In certain types of anisotropic formation, the skin associated with this flow regime is negative.
A new family of dimensionless type curves is presented which can be used to quantify permeability anisotropy from the pressure response at the disturbing well only. The type curves have been generated numerically but limiting cases have been compared with available analytical solutions to confirm accuracy. The effects of wellbore storage and producing time on pressure response are also considered. Pressure responses are observed to be similar to those from other lateral hetrogenieties. This lack of unique model reinforces the need to interface with other disciplines in well test interpretation.
Field and synthetic examples are used to illustrate use of these type curves.