bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waterflood Optimization of the Buffalo Coulee Bakken Heavy Oil Pool of Southwestern Saskatchewan
Authors: Ko Stephen C. M. , Domier Duane B. , MacDermott Richard N. 
Published: December 2007

Abstract
Since 1969, a waterflood scheme has been implemented in the Bakken sand heavy oil reservoir in the Buffalo Coulee field of southwestern Saskatchewan. Even with 20-acre well spacing in the waterflood area located in section 22-32-24 W3M, projections of oil recovery appear to be low, especially in the northern half of the section where much of the original gas cap still exists. Reservoir simulation was employed to investigate the potential of well spacing reduction from 20-acre to 10-acre by infill drilling, the merit of additional water injection into the reservoir, and the effect of gas cap blowdown on oil recovery. A reservoir model representing section 22 and the surrounding waterflood area was calibrated by history matching the historical production and injection performance of the 48 wells in the study area. Based on history match results, the shale layer between the oil pay and the gas cap provides a vertical permeability barrier in the gas cap area of the reservoir. This was confirmed by the findings of a recently drilled well where injected water was found to have completely flushed the gas cap, resulting in water currently situated on top of the oil zone in that portion of the reservoir. Based on performance predictions conducted on the calibrated reservoir model, the current 20-acre well spacing is adequate for the waterflood scheme in the pool, since infill drilling with either vertical or horizontal wells will not recover any significant incremental oil reserves. Furthermore, blowing down about 14.9 × 106 m3 of gas from the gas cap will have no detrimental effect on the estimated oil recovery of about 18% of the original oil-in-place (OOIP), based on current water injection rates in section 22. If water injection in section 22 is increased by about 50%, oil recovery from section 22 can be improved to about 22% of the OOIP, corresponding to an incremental oil recovery of about 76,000 m3, or 4% of the OOIP.
An Update of Steam Injection Operations at Naval Petroleum Reserve No. 3, Teapot Dome Field, Wyoming: A Shallow Heterogeneous Light Oil Reservoir
Authors: Doll T. E. , Luers D. K. , Strong G. R. , Schulte R. K. , Sarathi P. S. , Olsen D. K. , Hendricks M. L. 
Published: December 2007

Abstract
The Shannon light-oil (32–34° API gravity) steamflood at Naval Petroleum Reserve No. 3, (NPR-3) Teapot Dome field, Wyoming, was initiated in 1985 as a result of favorable production response to steam preheating in the in situ combustion pilot earned out in the early 1980's. Favorable but mixed success of two 10-acre steamflood pilots led to commercial scale operation in 1987. To date, the steamflood project has steamed 210 acres, 90 acres of which is currently being steamed with three 50 MMBtu/hr steam generators. The performance of the steamflood is reviewed in light of the dominant role that the reservoir's complex geology plays, since both injection and production wells are greatly influenced by the localized, highly heterogeneous geology of the consolidated, tight, faulted, and extensively fractured sandstone composing the Upper and Lower Shannon. Pattern step out is dominated by the geologic conditions that dictate each pattern's operation. Economics, mandates for profitability, and budget constraints have influenced the method by which the steamflood has been managed. Investigations of lower injection rate, variation in steam quality and the associated production response, as well as improvements in heat management techniques, are discussed. Increasing steam quality in pattern 5A led to incremental oil production of 44 B/D and a 2.5 times return on investment on the incremental gas used to fire the steam generator. Optimization of the steamflood depends upon accumulating and using information from pattern-specific operations.
Optimization Simulation on Steam Drive in Le'An Oilfield
Authors: Guanghe Li , Xiaolin Yu 
Published: December 2007

Abstract
Ng2 formation of fault block Cao-20 in Le'an Oilfield is a sand gravel heavy oil pool. Numerical simulation was run on two well patterns of inverted 9-spot with different lithology and well spacing as pilot areas for steam drive test. On the basis of history match of huff and puff with 3-D multi-well and multi-cycle, the prediction of simulation of thermal recovery is combined with the method of input and output using two type of tubings, the right time converting to steam drive and operation conditions for steam injection was optimized from the economic point of view. By integrating the research results, the optimum recommendation for the field has been put forward. In order to improve the steam drive recovery, the prediction on the result of infilling well pattern and minimizing the downhole flowing pressure of producers has been made. Moreover, the analysis of displacement mechanism of steam drive period, evaluation of the result of steam drive, and comparison of the similarities and differences of geology and production of two well groups have been made.
Experimental and Numerical Simulations of a Novel Top Down In-Situ Combustion Process
Authors: Coates R. , Lorimer S. , Ivory J. 
Published: December 2007

Abstract
A new in-situ combustion strategy, the top down process, is currently under detailed laboratory study. The process, aimed at overcoming some of the problems that have restricted the successful application of in-situ combustion in oil sand and heavy oil formations, involves the stable propagation of a combustion front from the top to the bottom of a reservoir, exploiting gravity drainage of the mobilized oil to a lower horizontal well.
Operational parameters that have been investigated and presented here include: air injection flux, degree of pre-heating, internal steam flood pre-heating and injection of normal air versus injection of oxygen enriched air.
To compliment the experimental investigation, the thermal numerical simulator STARS has been applied to the in-situ combustion process by incorporating reaction kinetics for Athabasca oil sand. A successful history match of an experimental test is presented accompanied by a discussion of application of the model to field scale,
Design of a Steam Pilot in a Fractured Carbonate Reservoir - Qarn Alam Field, Oman
Authors: Macaulay R. C. , Krafft J. M. , Hartemink M. , Escovedo B. 
Published: December 2007

Abstract
Steam injection has been identified as the most promising recovery method for the intensely-fractured carbonate Shuaiba/Kharaib/Lekhwair reservoir in Qarn Alam, Oman. The reservoir contains 213 million m3 of heavy viscous (16 °API, 220 cp) crude, however the ultimate recovery efficiency under primary recovery is expected to be only 2 % of stock-tank oil initially in place (STOIIP) because of the strong natural aquifer drive via the fracture system and the oil-wet nature of the rock. An intensive programme of analytical, experimental and reservoir simulation studies has been carried out in order to quantify the potential gains from a thermally-accelerated gas-oil gravity drainage (GOGD) process, and to design and interpret a pilot project in the crest of the reservoir. Steam injection is expected to raise the recovery factor to 20 % or more, but there are large uncertainties associated with the performance of the process. The pilot project will test the application in the field commencing late 1995 and is planned to last for about five years.
The Feasible Conditions Study of Steamflooding for Heavy Oil Reservoirs In China After Cyclic Steam Injection
Authors: He Z. , Zhang R. , Pu H. V. , Ren X. 
Published: December 2007

Abstract
China is rich in heavy oil reserves. In recent ten years, the production of heavy oil has rapidly grown through application of steam injection and the annual production reached up to 11. 9 million tons in 1993. At present, with the increase of cycles of steam injection, the effectiveness becomes poorer and the challenge of changing steam stimulation into steamflooding has to be confronted. Because of heavy oil reservoirs in China characterized with complex geological conditions, deeply buried, multi-layers and serious heterogeneity, especially some complicated conditions occurring in steam cycling, the effectiveness of steamflooding pilots has not been ideal commonly. Therefore, it is urgent to study and determine the comprenhensive conditions at which the reservoirs are feasible to be converted from steam cycling to steeamflooding at the present technological situation.
In this paper, based on three typical types of heavy oil reservoirs, systemetic studies have been conducted to investigate the effects of oil viscosity, oil formation thickness, vertical permeability difference, reproduction ratio of injected water in steam cycling and channelling path etc. on steamflooding effectiveness. Then, a practical screening criterion of steamflooding is proposed to provide technical bases for the conversion.
Prediction of Technological Properties of Tatarstan Natural Bitumens on the Basis of Chemical and Geochemical Characteristics of Their Composition
Authors: Kayukova G. P. , Romanov G. V. , Arbuzov A. E. 
Published: December 2007

Abstract
This paper is devoted to solution of problems connected with forming deposits of heavy oils and natural bitumens in Permian sedimentations on the territory of Tatarstan and to questions of prognostic evaluation of their technological properties in relation to degree of their natural transformations. Comparative investigation of composition and properties of their various representatives (heavy oils, malts, asphalts and asphaltites) occurring on drill log and proved area of Permian producing deposits on the territory of m Tatarstan in depth interval from 1 to 349 m was carried out, in connection with solution of problems on preparation of natural bitumen fields to development. The systematization of studied samples recovered by both natural inflow from wells and their extraction from bitumen saturated rocks of various age and mineralogical composition by oil-bitumen-bearing complexes, and within the last ones, by relation to local erosion basis, allowed to reason that characteristic changes in the composition bitumens leading to formation of their various chemical types are determined mainly by biodegradation process presenting practically in all oil-bitumen-bearing complexes and, especially, enhancing in carbonate reservoirs and horizons consisting of fragmental terrigenous sedimentary rocks undergone the washout and inluence of external factors.
References and illustrations at the end of paper
It was shown that biodegradation processes leading to absence of light hydrocarbon fractions in their composition, including normal and isoprenoid alkanes, and predominance of resin- asphalt compounds enriched by hydroxyl and ester oxygen, along with sulfur and nitrogen atoms, determine technological properties of natural bitumens during their recovery and processing.
The In Situ Formation of Heavy Oil Emulsions
Authors: Cuthiell David , Green Kirk , Chow Ross , Kissel Gerald , McCarthy Clare 
Published: December 2007

Abstract
Heavy oil is commonly produced in the form of water-in-oil emulsions. It has long been debated whether the emulsions are formed in the reservoir, and if so, what effect they have on the recovery process. This work examines the conditions under which water-in-oil emulsions can form in situ, and their flow properties.
A number of experiments have been carried out in which water and oil were injected as separate phases into a sandpack, and the produced oil analyzed for emulsified water content. We find that emulsified water content is small at low injection rates, but that above some threshold rate, the water content rises rapidly. Dependence of the threshold rate on oil type, oil viscosity, water;oil ratio, pack permeability and pack wettability have all been examined.
Our results suggest that oil phase capillary number, Nc, defined as (oil velocity)x(oil viscosity)/(oil-water IFT) is a natural dimensionless parameter to describe the emulsification threshold. For oil viscosity much greater than that of water, and permeability of the order of a few darcies, threshold Nc is between 104 and 10−3. Such capillary numbers are commonly encountered in near-wellbore flow during heavy oil recovery operations.
Experiments comparing a reservoir oil with mineral oils show similar threshold capillary numbers. The threshold increases with permeability of the medium and is significantly lower in oil-wet compared with water-wet sand. Preliminary results indicate that a significant reduction in effective mobility of the oil phase occurs when emulsification takes place.
A New Rig for Lean Times: NDES For Brent Charlie
Authors: Wehling B. , Franzenburg C. -P. , Gmyr P. , Bosse D. 
Published: December 2007

Abstract
The criteria established for proceeding with the Brent Charlie platformNew Drilling Equipment Set (NDES) are safe operation, fitness for purpose, improved workenvironment, reduced rig crew and cost effective design. The project is being implemented with an EPC (Engineering, Procurement, Construction) Contract by a JointVenture (JV) between a German drilling and oilfield systems engineering and construction company and a British fabrication company.
Following the successful demonstration of a semiautomated rig for the Continental Deep Drilling Project (KTB) in Germany, the operating company was satisfied that incorporation of similar state-of-the-art drilling systems technology in the NDES would underpin the economic case for this project.
The transfer of land based technology to offshore applications will be appropriately profiled.
The drilling rig is tailored to meet the present and future needs on the Brent Charlie platform. This rig is the response to the specific requirements of the drilling industry, namely - advanced technology, cost within reasonable limits, and the highest possible safety standards.
The principle design features are remote operations from an enclosed operator's cabin where the driller's and assistant driller's controls, including pipe racking, are all powered functions, together vyith advanced and proven drilling technology and equipment such as handling drill pipes in triples, and making up or breaking out of triples simultanesouly whilst drilling. Proven state-of-the-art automation systems will greatly improve the cost effectiveness of the platform. Ultimately this will provide faster drilling times, provide a safer drill floor working environment, reduce down times, and reduce the number of drill crew required to operate the rig. Many of these systems can be easily incorporated into existing rigs.
The relative benefits and cost savings of the various systems will be presented.
Conceptual engineering design has recently been completed. Detailed drilling systems engineering, procurement and manufacture is now being carried out by the JV team. The partners' commitment to the industry CRINE initiative has achieved further economies. Fabrication and installation of systems and equipment will be carried out in Scotland where the rig will be on display during the commissioning activities. The final completion stage will be during the SPE conference in September, ready for sailaway in December 1995.
The Brent NDES is designed for a working life of approximately 25 years with an anticipated rig shutdown time for maintenance of no more than twoweeks per year and is equipped to handle all present and future drilling operations. The result is a unique drilling rig that not only surpasses all the technical requirements, but is also economical to operate.
Cost Effective Well Abandonment
Authors: Jordan Russell , Head Philip 
Published: December 2007

Abstract
Well abandonment is now becoming an important consideration for many operators, particularly in ex-pensive offshore locations. The traditional methods are very expensive to apply, and it is important to remember have a negative economic impact, other than good housekeeping.
An innovative technique has been developed to en-able all the well casing annuli to be permanently sealed in a single operation. A simulated well aban-donment using this technique is planned for the sum-mer of 1995 and the results will be presented together with time analysis and cost estimates.
HPHT Drilling and Completion Design for the Erskine Field
Authors: Elliott G. S. , Brockman R. A. , Shivers R. M. 
Published: December 2007

Abstract
This paper summarises the factors influencing the well design for a high pressure high temperature (HPHT)* field development using a Not Normally Manned Installation (NNMI) in the UK sector of the Central North Sea (CNS).
Partnering and Alliances: Theory and Practice
Authors: Green Richard L. 
Published: December 2007

Abstract
This paper outlines some of the theories associated with the development of collaborative relationships (partnering and alliances) between companies which have shared objectives. It then reviews research carried out at The Robert Gordon University on relationships between operators and their contractors in the United Kingdom Continental Shelf (UKCS) Oil and Gas Production Industry. Basic data has been collected on 175 relationship and more detailed data has been obtained on about 20 relationships by interviewing the people involved. There is a wide variety of relationships in place in the industry and they are at differing stages of development. Views on the benefits and practicality of collaboration vary across the industry. By and large, comments received from the people involved in creating and managing collaborative relationships confirm the messages arising from the theory. The importance of behaviour and attitudes of the people involved at all levels is emphasised.
There is uncertainty and concern among the smaller contracting companies about how the market is evolving and how to react to it. Current theory does not appear to provide much assistance with this problem. There is also concern that the current developments can lead to a stifling of innovation among the smaller companies. The paper summarises the comments received on this subject.
The Harding Field: A Low Development Cost per Barrel Concept Becomes a Reality
Authors: Smith S. L. 
Published: December 2007

Abstract
BP's Harding Development employs a totally innovative concept for North Sea oil production. A large permanently insUiiicCi jack-up platform, incorporating production, drilling and living quarters facilities, is positioned on top of a concrete gravity storage base tank which holds Harding's acidic heavy crude before export, via a submerged turret loading buoy, to shuttle tankers. The use of horizontal drilling techniques in the early 1990's coupled with adoption of the above concept transformed a very marginal prospect into a viable development which currently has one of the lowest development costs per barrel in the North Sea.
The paper describes how the viability of the development has been achieved using an entirely new approach to project management by BP with a small integrated management team. The relationships created with design contractors, suppliers and fabricators are shown to represent the embodiment of the principles of the CRINE initiative and have secured for all parties benefits which can be used as benchmarks for future projects in a low oil price environment. Contractual arrangements are discussed and a new approach to Operations and Maintenance support contractors is highlighted.
The concept has potential for reducing abandonment costs due to the relative ease of decommissioning and removal.
Whole Life Cost Joint Industry Project
Authors: Crabb J. 
Published: December 2007

Abstract
Background
There is a growing awareness that Whole Life Costing (WLC) principles offer benefits in assessing the cost of projects, facilities and equipment before commitments are made. As a management tool they provide for options to be compared and for system cost-effectiveness and value-for-money to be optimised.
Properly understood and applied, WLC principles provide a powerful analytical capability: coupled with logistic support and economic analysis techniques they provide the means by which cost drivers and dependencies can be identified, targeted and more effectively managed.
Current Status
Although individual operators have started to apply WLC principles as part of their own development studies, advancement has been constrained. This is mainly due to different interpretations of WLC methods, techniques and requirements.
Design Principles and Material Failures During Operation
Authors: Strandmyr Ø. , Bakken K. A. 
Published: December 2007

Abstract
Corrosion failures in piping systems and associated equipment on offshore platforms cost our Company multimillion US dollars per year.
There are many different reasons for the corrosion failures. This paper will discuss some of the factors related to design and how these design parameters are met during the operating phase. Concrete examples from Statoil operated offshore platforms illustrate some typical corrosion failures.
Many actions have been taken to improve the engineering phase involving material selection. Communication between involved disciplines and representatives from operating departments and end users have been improved with socalled integrated project teams. At the same time has work been done to improve the design basis.
The ultimate goal is to reduce capital costs and costs during operation and at the same time operate to the highest safety standard.
Evaluation of Compact Steam/Water Separation Equipment for Gas/Oil Systems
Authors: Birmingham D. P. , Davies S. R. 
Published: December 2007

Abstract
The possibility of using existing steam/water separation equipment for compact gas/oil separation applications has been evaluated and is believed feasible.
A single separator pair operating at 880 psia is estimated to have a separation capacity of 28,000 BPD oil and 15 MMSCFD gas for a water drive reservoir, and 17,000 BPD oil and 15 MMSCFD gas for a gas drive reservoir. Larger capacities are expected at lower pressure. Efficient separation is expected over a wide range of flows, liquid levels, and pressures. The vertical orientation of the separator allows it to be contained within a 24-inch diameter pressure vessel.
Potential areas where this compact separation equipment may be beneficial include primary separation for minimum facility platforms, vertical high pressure gas/liquid separation, retrofit/add-on capacity, combined slug suppression and preseparation, gas/liquid separation for floating production systems and subsea applications. The major benefits are expected to be its compactness, small footprint and weight, and the modularity of the design.