bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Thermal Recovery Processes in Heavy Oil Carbonate Reservoirs
Authors: Das Swapan 
Published: December 2007

Abstract
As the demand for oil grows, the petroleum industry is expanding the technology envelope to access and exploit many unconventional resources. The current focus of all major oil companies is heavy oil in highly porous and permeable sandstone reservoirs (oil sand), which presents a significant opportunity. However, viscous oil trapped in carbonates (over 1.6 trillion bbl)1, potentially a huge resource for future, needs application of new technologies to be exploited economically.
At present thermal processes like steam flooding and cyclic steam stimulation (CSS) are being used extensively for the recovery of moderately viscous heavy oil from sand stone reservoirs. Another thermal process, SAGD (steam assisted gravity drainage) is being used for the recovery of higher viscosity heavy oil and bitumen from oil sand. Some of these processes are apparently very successful with ultimate recovery over 80%.
Application of thermal processes to the carbonates poses a different challenge. In general, thermal recovery in carbonates is highly energy intensive and hence, economically challenged. Due to adverse wettability (generally mixed or oil wet), lower matrix permeability, the anticipated recovery using thermal processes is much lower compared to sand stone reservoirs. With increased access of the reservoir through horizontal wells there is a possibility that these resources can be exploited economically. A simulation study has been undertaken to explore the possibility of application of thermal processes in carbonate reservoirs. Based on the results of this work, this paper presents different possible recovery options and examines the sensitivities of reservoir parameters on thermal recovery processes like CSS and SAGD in fractured carbonate heavy oil reservoirs. The results suggest that SAGD may be viable in some of these reservoirs.
Drilling With Liner on Horizontal Oil Wells
Authors: Terrazas M. , Estrada M. , López V. M. , Jardines A. , Díaz E. , Fisher M. 
Published: December 2007

Abstract
This paper describes lessons learned and results obtained while applying a rotary drilling with liner system on conventional rigs, during the planning, design and drilling operation in offshore wells located in the Mexican coasts of the Gulf of Mexico.
Due that the cretacic formation named El Abra is composed by naturally fractured limestone and since its structural top (origin reef) has been eroded, it is difficult to detect it. Moreover, the differential pressure between the Tertiary and El Abra, result in several hole problems, such as: severe lost circulation, stuck pipe, cave-ins of holes and bad casing cementing jobs. These problems have increased time and cost in the drilling projects.
Continuous searching for alternative solutions with new technology to solve specific problems in the drilling process, lead PEMEX Exploration and Production to apply the non conventional option of rotary drilling with liner, meeting the safety standards established by the company.
The applied drilling with liner system, has allowed to drill down to the objective depth with high angle, cement the liner and drill out the following interval horizontally, steering in the reservoir. The system consists of a shoe drillable bit, a float collar, stabilizers, a liner with integral flush connections of high torque and a rotary liner hanger.
The results of the technique are presented utilizing a liner of 9 5/8" and a bit of 12 ¼", also hydraulic analysis, stress generated in the casing and the connections by 75° angle of hole construction, torque and drag, and drilling parameters. A comparison with conventionally drilled wells is performed, pointing out the problems found in the field, the results achieved, and how by applying the technique drilling with liner, savings of 40 days time and 5.0 MM usd per well, have been accomplished.
Development of a New Artificial-Neural-Network Model for Predicting Minimum Miscibility Pressure in Hydrocarbon Gas Injection
Authors: Birang Y. , Dinarvand N. , Shariatpanahi S. F. , Edalat M. 
Published: December 2007

Abstract
Miscible gas injection is one of the most effective enhanced oil recovery techniques and minimum miscibility pressure (MMP) is an important parameter in miscible gas injection processes. Exact determination of this parameter is critical to the designing of the injection equipments and the project investment prospect. The purpose of this paper is to develop a new artificial neural network (ANN) model to predict the minimum miscibility pressure of hydrocarbon gas flooding.
Different MMP correlations and models regarding the kind of injection gas and the mechanism of miscibility have been proposed, which are respectively based on mathematical and thermodynamic calculations. Almost all the correlations proposed in the literature are representative of either condensing or vaporizing mechanism or give reasonable results only in the limited range of data they are based on. In this article, by taking into consideration both condensing and vaporizing mechanisms and by using a wider range of data, the new model is introduced. Experimental data from different crude oil reservoirs carried out by slim tube test have been used to obtain a new model in which both mechanisms are included.
An Iranian oil reservoir is a candidate for miscible gas recycling with API=23 and initial pressure of 5500 psi. Sampling and recombination is done on the reservoir fluids. Flash and differential expansions are performed for fluid characterization and then miscible experiments are carried out for MMP determination with slim-tube apparatus.
The significance of this correlation is that MMP can be determined for any composition of oil and gas, no matter which mechanism is dominant in achieving miscibility. The sensitivity analysis is done and consequently the percentage of error for the model is compared with the literature data. It is shown that the results obtained from the new MMP model are more accurate when compared with other most common correlations reported.
Reservoir Candidate Screening is Critical to Ensure Successful Application of Underbalanced Drilling Technology- Case study
Authors: Babajan Salar , Qutob Hani 
Published: December 2007

AbstractThe Petroleum Development of Oman, PDO has been considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their fields. Among the various options available to achieve these objectives, Underbalanced Drilling technology is considered to evaluatthe benefits over traditional drilling and completion methodologies in terms of reservoir performance.Accordingly, an Underbalanced Drilling reservoir candidate screening process was initiated to examine the suitability of the technology for seven gas reservoirs in PDO.The screening process began by taking basic reservoir and drilling data and processing it through expert system software. The software rated the candidacy of the reservoir to help determine the likelihood of achieving success with underbalanced vs overbalanced drilling and completion techniques, to identify the best potential underbalanced candidates from the given portfolio and proceed with a detailed analysis.The expert system score for underbalanced candidacy is calculated by considering different modules. Each module includes a comparison of the key differentiators between overbalanced and UB techniques that impact the UB candidacy of a reservoir. To make these comparisons, the expert system assumes a well is drilled overbalancedand assesses the potential effect on reservoir performance and then estimates the potential benefit of underbalanced drilled wells with minimal damage.In this paper, the results of the screening process for the gas reservoirs examined are presented and discussed. The study confirmed that candidate selection is a critical first step before initiating any underbalanced drilling project. It also explains why when correct candidates are chosen, UBD significantly improves productivity compared with conventional overbalanced drilling practices.
Combination of Drilling With Casing and Stage Tool Cementing: A Unique Approach to Mitigating Downhole Conditions
Authors: Robinson R. , Rosenberg S. , Lirette B. , Odell A. C. 
Published: December 2007

Abstract
The gas fields of the western Piceance basin in northwestern Colorado present significant challenges to drilling and casing operations. This area has complex geology, with dipping formation beds that lead to "crooked hole" drilling. Fractured formations cause problems, including lost circulation while drilling, and failure to return cement to surface during primary cement jobs of the 9 5/8-in. casing. Sometimes casing cannot be run to total drilled depth.
After review of the problems, an operator in the region concluded that a different approach was warranted and selected drilling with casing (DwC) as an alternative to investigate. DwC, combined with stage cementing of the surface casing, was expected to yield a significantly more effective surface-hole drilling and casing operation, reducing nonproductive time (NPT) and the associated cost.
This paper reviews the problems encountered in conventional surface-hole drilling and casing running operations in the Piceance basin. It also reviews the operator's decisions for a DwC approach. A case history of a DwC-with-stage-tool cementing operation and its successful conclusion is presented.
World's First Annular Safety Valve for Dual Concentric Water Injection
Authors: Pearce K. A. , Skorve H. G. , Grini M. 
Published: December 2007

Abstract
The Hibernia field is located in the Jeanne d'Arc Basin on the Grand Banks of Newfoundland, approximately 315 km east southeast of St. John's (Fig. 1). The Hibernia Gravity Based Structure (GBS) platform has a total of 64 slots available for well construction and currently only a limited number of well slots remain. Since production began in 1997, it has become apparent more than 64 wells will be required to develop the resources adequately. As such, it was recognized a platform slot constraint issue could become a limiting factor for the timing of development of the remaining resources.
To optimize the use of the remaining slots, a unique technical solution was developed. The design concept was to drill a well through the upper Ben Nevis - Avalon (BNA) reservoir (G Block) and into the Hibernia reservoir (DD Block). This well (WIDD1/AWIG1) was the first Hibernia dual concentric water injection well. To realize this design concept, the world's first annular safety valve for dual concentric water injection was designed, manufactured, fully tested, and qualified in a fast track manner to enable injection into the annulus for the upper BNA target and through the tubing for the lower Hibernia target.
The WIDD1/AWIG1 well was successfully drilled and
completed allowing dual concentric injection as envisioned in the original well proposal. To date, one additional dual concentric injector well has been drilled and other dual concentric well concepts are actively being pursued.
Liquid Cement: Changing the Paradigm
Authors: Eid Ramy N , Mays Patrick 
Published: December 2007

Abstract
The process of oil well cementing has changed little since the introduction of the ground jet-mixer eighty years ago. While time has brought advancements such as; pneumatic transfer of bulk cement, introduction and application of the re-circulating mixer, liquid additives, advanced density control and additive measuring devices, the basic elements of well cementing have remained largely unchanged over time. In an offshore cementing environment the process involves the pneumatic transfer of cement or cement blended with dry products to a supply boat and the pneumatic transfer of this material to the offshore rig's storage tanks. The material is then pneumatically transferred a third time to the cement unit, where water is added and the slurry is homogenized by a large and expensive cement unit, usually coupled to a batch mixer. This tedious process occurs even on small jobs and in remote facilities.
To simplify the process, a new concept using a Liquid Cement Premix (LCP) has been developed. As its name implies, LCP is basically pre-mixed storable cement slurry that can be stored for an extended period in a homogenous fluid state and then can be used in any number of down-hole applications just like conventional cement. There are many benefits implicit in the application of this new technology. Among these are reduced environmental impact, improved quality control, reduction (or even elimination) of conventional cementing and associated equipment, elimination of cement blending and enhanced logistics for remote platforms, reduced in required personnel offshore and considerable time savings. Particularly interesting is the use of this concept for work-over and abandonment operations in situations where deployment of conventional cementing equipment would be impractical or expensive.
This paper presents the background of LCP and describes a common example of a field implementation.
New Risk-Management Standard for Delivering Superior Environmental and Safety Performance
Authors: Smith Andrew L. 
Published: December 2007

Abstract
Although ANSI approved ANSI / AIHA Z10-2005 – Occupational Health & Safety Management Systems in July 20051, the United States still does not have a National Risk Management Standard.
Risk management is not just something for corporations or public organisations, but for the life cycle of any E&P activity whether short or long term2. The benefits and opportunities should be viewed not just in the context of the E&P activity itself but in relation to the many and varied stakeholders who can be affected. By meeting the various component parts of this standard, our industry will not only be in compliance but can also measure itself against a new standard which represents best global practice.3
Risk management should be a continuous and developing process which runs throughout the organisation's strategy and the implementation of that strategy. It should address all the risks surrounding the organisation's E&P activities past, present and in particular, future. It must be integrated into the culture of the organisation with an effective policy and a programme led by the most senior management. It must translate the strategy into tactical and operational objectives, assigning responsibility throughout the organisation with each manager and employee responsible for the management of risk as part of their job description. It supports accountability, performance measurement and reward, thus promoting operational efficiency at all levels.
The focus of good risk management is the identification and treatment of these risks. Its objective is to add maximum sustainable value to all E&P activities of the organisation. It marshals the understanding of the potential upside and downside of all those factors which can affect the organisation. It increases the probability of success, and reduces both the probability of failure and the uncertainty of achieving the organisation's overall objectives.
Risk management is central to any organisation's strategic management. It is the process whereby organisations methodically address the risks attaching to their E&P activities with the goal of achieving sustained benefit in the form of delivering superior environmental and safety performance within each E&P activity and across the portfolio of all E&P activities.
Implementation of ROP Management Process in Qatar North Field
Authors: Remmert Stephen M. , Witt Joseph W. , Dupriest Fred E. 
Published: December 2007

Abstract
In March 2005, the operator implemented a rate of penetration (ROP) management process in Qatar's North Field. IPTC Paper 10706-PP describes the general principles behind the new work process and highlights its introduction to the operator. The ROP management process uses real time, customized surveillance technology to continuously maximize both drill bit cutter efficiency and transmission of energy from rig floor to the bit. This paper focuses on specific changes in drilling practices and their translation into substantive program acceleration and capital savings. To date, the development program has been accelerated by one year and USD 54 million has been saved while drilling 470,000 ft of hole. The process has proven to be a highly effective solution for management of drilling efficiency in a major development drilling campaign. As an indicator of program scope and effectiveness, over 440 personnel have been trained in mechanical specific energy (MSE) analysis, and 50 new field drilling records have been set by the nine rigs involved in the program. Importantly, the process has been implemented with one of the best safety records in industry (TRIR or total recordable incident rate of 0.11 per 200,000 man-hours as of September 06).
The Evolution of a TAML L–4 Multilateral System to Meet the Challenges of a BP Deepwater Subsea Well
Authors: Horne Ken , Allam Robbie , Glaser Mark , Chandler Peter , Scharf Thilo 
Published: December 2007

Abstract
The Schiehallion field lies in water depths of 1,150 to 1 475 ft and is situated west of the Shetland Islands. The reservoir was discovered in 1993 and first brought on stream in 1998. It is the largest field operated by BP in the region and is one of the largest producing fields in the UK sector. Currently there are 19 production and 19 water-injection wells in the field, which have yielded more than 250 million BOE to date.
At the outset, the North West Area Development (NWAD) of the Schiehallion field was planned to have four penetrations, consisting of two producers, each with its accompanying injector; however, design and economic reviews indicated that development with a multilateral well and matching injectors was more viable. The selected multilateral system consisted of a hollow whipstock through which perforations would be made after the completion was installed. While the perforating gun and low-side weight bias orientation system are not new technologies, they still required substantial qualification because of the unique construction of the well, driven primarily by well control policies and the requirement for an intelligent completion to facilitate independent flow control of both laterals. The resultant integration of technologies supplied by several service companies demanded rigorous testing and qualification of the various components. Several tests were performed to validate the viability of the completion design, such as perforating gun suitability; confirmation that minimal tubing deformation would occur; perforation hole sizes; the likelihood and containment of perforation debris; and testing of a straddle system required to bridge off the tubing perforations to isolate and control the mother bore production. The test program culminated in a full-scale stackup of the intelligent completion within a test well, followed by perforating and subsequent quantification of the debris generated and captured.
This paper details the development trials carried out on the perforation system required for this multilateral system to meet the needs of drilling and completing a subsea multilateral producer with an intelligent completion. In addition to discussing the physical testing, this paper summarizes the results obtained from erosion modeling and productivity evaluation, which also influenced the final well design.
Case Studies Of Emulsion Behavior At Reservoir Conditions
Authors: Kokal Sunil , Al-Dokhi Mohammed 
Published: December 2007

Abstract
Most emulsion studies are conducted with depressurized crude/water samples. Can emulsions form in the reservoir at high pressures and high temperatures? The answer to this question is generally anecdotal. This paper provides a unique method and new data from emulsion studies at high pressures and high temperatures. Two case studies will be presented where emulsions were suspected to be the cause of production challenges in several wells. The experiments were conducted in a special visual PVT cell with the capability of observing emulsion phase behavior at reservoir conditions. The effects of several variables on emulsion behavior were investigated including shear, pressure, temperature, watercuts, and asphaltene precipitation tendency of the crude.
The first case study is in a field that produces tight emulsions. The results of this study indicate that emulsions can form at reservoir conditions, with mixing, especially if the crude has a propensity to precipitate asphaltenes. The new data suggests that emulsion behavior is closely linked to the presence of fine solids through in-situ dynamic precipitation of organic (asphaltenes) and inorganic salts (scales) as well as fines migration in the reservoir. In the second case study, a series of emulsion tests were performed on bottomhole and wellhead samples from several wells. The results suggests that the emulsions are relatively loose at bottomhole conditions but become progressively tighter with a reduction in pressure and temperature. The tightness of the emulsions was linked to fine solids that stabilize them. These include primarily calcite and sulfur-rich heavy hydrocarbons like asphaltenes, with trace amounts of silicates (clays and/or fine grained silica), iron-rich precipitates and barite.
Magnolia Deepwater Experience—Frac-Packing Long Perforated Intervals in Unconsolidated Silt Reservoirs
Authors: Eaton Luke F. , Reinhardt W. Randall , Bennett J. Scott , Blake Kenyon , Morales Hugo 
Published: December 2007

Abstract
ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50°–60° maximum hole-angles. The wells are completed using dry trees from the TLP and are producing primarily from massive, fine-grained, Pleistocene-aged reservoirs.
These reservoirs require sand-control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high rate, long life completions, the producing zones are frac-packed. The average perforated interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft.
The typical production casing string for the wells consists of 10–3/4 in. casing with an 8–1/16 in. production liner. Drift diameter through the tapered production casing is 9–1/2 in. and 6–1/2 in. respectively. The 6–1/2 in. drift diameter allows using common size screens and packers. The wells are generally completed with a 4–1/2 in. × 3–1/2 in. tapered tubing string.
Premium screens with shunt tubes are used on the wells due to the long deviated intervals. The "frac-pack" stimulation treatments are pumped at rates of 27 to 40 bbl/min with a viscoelastic surfactant carrier fluid. Washpipe conveyed downhole pressure and temperature gauges and radioactive tracers are used to help analyze the treatment results.
This paper will discuss screen selection philosophy in silt/very fine sand reservoirs, carrier fluid selection, perforation strategy, and ability to frac across shale intervals. The paper will also cover the effectiveness of achieving a frac-pack with premium screens with shunt tubes, based upon downhole pressure, temperature, radioactive tracer information, and revised operational practices that resulted in zero to negative skin completions across long, perforated intervals that continue to produce sand free after extreme reservoir depletion.