bluuebunny/crossref_metadata_2025_split huggingface dataset:
Skin Rashes with Oil-Base Mud Derivatives
Authors: Cauchi G. 
Published: December 2007

Abstract
Skin rashes are a frequent problem of workers in the oilfield industry, especially on drilling operations using oil-base mud (OBM) products. The pathophysiology seems to be multifactorial, mixing heat effects with prolonged contact at friction points between the skin and protective clothing soaked with OBM chemicals. The symptoms are amplified at friction points and the major flexion bends of the body. Symptoms usually occur in a few days to one week after arrival on the rig, and disappear naturally at home, when there is no longer contact with OBM derivatives.
Clinical findings range from mild redness to severe skin erosions at the major flexion bends of the body. Initially dermatitis manifests as red, swollen, and blistered areas, while later stages may appear as crusted or scaly lesions. Symptomatic treatment involves using moisturizers, antihistamines, lubricants, and topical corticosteroids.
Why did I do that? From Unsafe Acts to Working Safely
Authors: Bryden Robin , Hudson Patrick , van der Graaf Gerard , Vuijk Margot 
Published: December 2007

Abstract
This paper builds on the culture and behavioural change work presented at previous SPE conferences focusing specifically on a new model for "Safe Behaviour". This model has led to the development of intervention tools, piloted within Shell companies in Africa, Europe and Middle East. This work supplements the existing Hearts and Minds toolkit, by targeting day-to-day worksite behaviour and driving behaviour, applicable for both drivers and managers.
The reason for this approach is not all hazards can be removed through an HSE-MS and supervisors are not always present so there remains a duty of care for those closest to the hazards to look after themselves and intervene with their colleagues whenever necessary. The function of the "Safe Behaviour" model is to help people understand why they don't always do what they should do and provide support for changing mindsets and behaviours. This is achieved by focusing on several key areas of safety behaviour from hazard spotting, to risk perception, through to interventions and developing good habits. After establishing areas for improvement, the tool provides techniques that small teams can use quickly and regularly on their own without any additional training to create a sustainable behavioural and attitudinal change.
Newly Designed API-Modified Sucker Rod Connection & Precision Makeup Method
Authors: Carstensen Kenneth 
Published: December 2007

Proposal

Abstract
The steel API sucker rod connection design used in beam and progressing cavity pumping systems has been an industry standard since the 1920's. During these many years of continuous use, improvements have been made both large and small, yet this three part connection system is responsible for the majority of rod string connection failures. After 3 ½ years of development, we now bring to the industry a new API modified four-part design with a method and system for precise make-up which expands load bearing capabilities and extends the working life of sucker rod connections. This paper describes development and testing work performed, information acquired, systems and methods created, and how the new API modified connection solves problems, eliminates or greatly extends time between failures, keeping work over and associated costs to a minimum. {See Figure - 1}
Clean and Lift - Heavy Oil
Authors: Holman Jesse 
Published: December 2007

Proposal
This paper will discuss artificial lift and clean out improvements in horizontal wells in the Potter Reservoir of the Midway-Sunset field located in California. Progressive cavity pumps, rod pumps, and effective sand clean outs decreased failure rates and increased production in horizontal wells. The failure rate decreased from 3.28 to 1.09 failures per year. Production increased approximately 240 barrels of oil per day (bopd) or 13 bopd incremental per well. Horizontal wells average 43 bopd while vertical wells average 12 bopd in the Potter.
Analysis and Synthesis of Horizontal Wells in Hassi R'Mel Oil Rim, Algeria
Authors: Recham R. , Bencherif D. 
Published: December 2007

Abstract
The objective of this study is to analyze the experience of drilling horizontal wells in Hassi R'Mel oil rim, Algeria. The excepted results are: higher well productivity, better oil recovery, lower water and gas coning, minimum cost of production operations and maximum profit.
For the Hassi R'Mel oil rim, recovery of the oil using only vertical wells is difficult because water and gas coning result in low oil production rate and high cost of production operations. Then using only vertical wells exhibit a drilling of a large number of wells which could affect the profitability of the development project especially in the presence of thin oil thickness.
A field development of Hassi R'Mel oil rim is needed, the technique of drilling horizontal wells is chosen as an alternative to some vertical wells, since horizontal wells provide options whereby pressure drawdown can be minimized, coning tendency can be minimized, high oil production rate can be achieved and consequently the cost of production operations can be reduced.
The first horizontal well HRZ-01 in Algeria was drilled in 1991 in Hassi R'Mel oil rim. Since, many horizontal wells have been drilled based on the optimization simulation study of the Hassi R'Mel oil rim development. Eight horizontal wells were chosen for this study with the objective to analyze their performance and assess their profitability.
Summary of Multilateral Completion Strategies Used in Heavy Oil Field Development
Authors: Cavender Travis 
Published: December 2007

AbstractIn heavy oilfield development, optimal flow rates usually directly correlate to reservoir exposure. In the case of heavy-oil development, reservoir exposure will play an even greater role because of the inherent flow-resistant characteristics of this type of hydrocarbon. For this reason, heavy oil completions have not been exploited fully. However, by implementing horizontal drilling and the state-of-the-art completion methods now available, heavy oil fields are now being revitalized.By employing multilateral technology (MLT), the benefits of horizontal drilling and state-of-the-art completion practices can be magnified still further. A drastic increase in the reservoir exposure from a single surface location can be strategically placed within the reservoir using multiple horizontal laterals. This development strategy reduces the number of surface locations and facilities, subsequently decreasing the overall field development costs. The added benefits are accelerated production and enhanced oil recovery, which increase the net present value of the asset.In multilateral implementation, the reservoir characteristics will always dictate the lateral window placement relative to the reservoir body along with the type of lateral interface with the parent bore. There are various types of lateral interfaces with the parent bore, which have been classified by the Technology Advancement of Multi-Lateral (TAML) Organization.This paper will review various heavy-oil multilateral applications and will include window construction and the integration of lateral completion strategies such as openhole liners and gravel-pack applications. It will also focus on other multilateral issues such as lateral accessibility and isolation techniques, remedial options, and guidelines for selecting a "fit-for-purpose" lateral window system.
Well-Testing Challenges of the Hamaca Project, Orinoco Heavy Oil Belt, Venezuela
Authors: Piña-Acuña Gloria , Ferreira Diomar 
Published: December 2007

Abstract
Petrolera Ameriven (PA), an operating agent owned by ChevronTexaco, ConocoPhillips and Petroleos de Venezuela, S.A., is developing the Hamaca project, the fourth in a series of large scale integrated extra-heavy crude production and upgrading projects, being developed in the Orinoco heavy oil belt, eastern Venezuela. The project encompasses production, processing, and transport of an 7.0 to 9.0 API extra heavy oil to be upgraded into 26 API.
The oil, produced under solution gas drive, is characterized by foamy oil behavior and the formation of very stable gas-oil and oil-water emulsions. Separation and independent measurement, of each one of the phases, can not be efficiently accomplished under these circumstances, making it challenging to measure oil, water, and gas in the production streams. Additionally, the heavy oil is currently mixed with a 26 API crude diluent at the wellhead, to improve mobility of the fluid and facilitate pipeline transport. Introduction of the diluent, of varying quality, during the first stage of surface production, adds to the complexity of well testing operations in Hamaca. This paper presents the well testing experience and evaluations performed in the Hamaca project, through the use of conventional well test separators and multi-phase meters. Each one of these well tests systems have presented a different set of operational challenges, and have required a different set of solutions to be implemented, in order to ensure good quality and representative well test results, which are vital to the performance evaluation of wells.
Application of a Reverse-Emulsion-Breaker at a SAGD Pilot Plant in Northern Alberta
Authors: Wang Sanyi , Axcell Eric , Cleary Robert , Little Virgil , Pinkoski Lon 
Published: December 2007

Abstract
For an extended period of time water-quality problem was experienced from the water leg of the primary treater, so-called high-temperature separator (HTS), which resulted in limited water-disposal in a SAGD facility near Fort McMurray, Alberta. A reverse emulsion breaker was recommended based on bottle testing data and a chemical application program was developed to clarify the produced water and to remove this major bottleneck of the system operation.
Bottle testing a wide range of reverse emulsion breakers with the fresh reverse emulsion from this SAGD facility resulted in two products that were plant tested at various locations in the plant and correlated with the chemical performance. During lab testing the quality of the water resolved from the reverse emulsion was determined both qualitatively (visual observation with a ranking card) and quantitatively (with a turbidity meter) for a range of chemicals, chemical dosages and agitation levels.
The method of chemical application has also proven to be as important as chemical itself. Chemical injection directly upstream of the HTS did not perform well, but moving it farther upstream from the HTS produced clean water within several hours from the commencement of the plant test. The percentage of water recycled from the produced water tank into steam generation was increased from 20% to 80%, thus not only removing the bottleneck but also presenting huge savings to the facility. It was demonstrated that working together with the SAGD operation staff to modify the chemical program would give mutual benefits to both parties involved.
Assessment of Oil Rate Measurement Accuracy Using Standard Separators to Monitor High-Temperature Cyclic Steam Wells
Authors: Webb Charlie , Castrup Suzanne Griston , Gaeta Gary 
Published: December 2007

Abstract
Accurately monitoring oil production from individual wells is essential for optimizing the economic performance of any primary or enhanced oil recovery project. In this regard, the cyclic steaming process used in the ChevronTexaco 1Y Antelope project introduces unique well gauging challenges. Steam is injected into low permeability; siliceous shale reservoirs at roughly 1,000 psi pressure (∼ 540°F). During a well's production cycle, hot liquids, gases and steam flow to the surface. The production cycle of these flowing wells is short-lived, typically ranging from 3 to 4 weeks, with flow rates declining rapidly during the first week. The ratios of water, oil and gas production also change over time. Fluids entering the automatic well test (AWT) units can exceed 350°F, especially during the early stages of the production cycle.
This paper presents the results of comprehensive testing and analysis of the existing 1Y Antelope AWT units, which consist of horizontal pressure vessels to separate and meter oil, water, and gas. Key components also include a coriolis mass flow meter and a capacitance-based cut probe. The results of field tests to assess the impact of vessel size and fluid temperature on separation efficiency and emulsion stability are presented. Test results showing the impact of fluid temperature on cut probe performance are also presented. Recommended equipment and procedural modifications to improve oil rate measurement accuracy are discussed. Finally, comparisons of oil rate measurement accuracies for existing and improved AWT equipment are presented.
Evaluation of Pressure Derivative Algorithms for Well-Test Analysis
Authors: Escobar Freddy Humberto , Navarrete Juan Miguel , Losada Hernán Darío 
Published: December 2007

Proposal
Pressure well tests performed during any stage of the life of a well are a very important tool to obtain fundamental reservoir characteristics. Also, they are one of the closest views obtained from the reservoir. Well testing is so important that an estimative of hydrocarbon reserves can be obtained. Also, it is possible to determine reservoir flow capacity and distance to discontinuities, among several applications.
Currently, pressure derivative analysis used in well testing is a very versatile procedure for reservoir characterization. However, this parameter is affected by the noise produced by turbulence, the tool itself, and the mathematical procedure involved. Therefore, it is important to properly use numerical tools to filter data. The pressure derivative function has become the most popular technique to interpret well pressure data but it suffers of noise since it is based on numerical differentiation on discrete pressure data points. The three-point central-finite different scheme has been widely used to estimate pressure derivatives. Noise occurs when consecutive points are used. It makes difficult to carry out an interpretation. Then, it is convenient to choose points further separated from each other to reduce the noise. However, if the points are so apart, the pressure derivative will be distorted. The Spline function is a powerful tool to calculate pressure derivative data for well test applications. Its continuous character and its polinomial behavior make it very effective to mitigate noise. It matches well to the expected form of the curve.
In this paper, an evaluative analysis of the pressure derivative is presented. It is performed by comparing the results from different algorithms (Spline, Bourdet, Horne, Simons, Clark and Van Golf-Racht, first degree and second degree polynomials), and observing theoretical pressure vs. time data with those provided by the chosen analytical solutions. It was found that the Spline function provides the best results to estimate pressure derivative data. Besides, the recommended procedure consists of differentiating the data and, then, filtering and/or smoothing them.
Tractor-Conveyed Sensors and Chemical Packer are Utilized to Remediate an Extended-Reach Horizontal Uncemented Slotted Liner Completion in a Siliceous Shale Reservoir, Kern County, California, USA
Authors: Formica Jeff , Wise John , Boye-Moller Christian , Davis Bob , Godfrey Bob , Walker Chuck 
Published: December 2007

Abstract
A downhole well tractor system was used in Kern County, California, USA, to convey production logging sensors into a horizontal uncemented slotted liner to determine the production profile and later coiled tubing was used to place an annular chemical packer in an effort to shut off water production.
The siliceous shale reservoirs of the Monterey formation of Kern County are very different from conventional sandstone and carbonate reservoirs. Production is primarily from thinly laminated porcelanite. One of the fundamental problems that hinder exploitation of the shale reservoirs is accurate identification of hydrocarbon and water resources. Production is achieved through extremely small pores and enhanced through small- to large-scale natural fractures. Drilling and completion techniques include extended-reach horizontal uncemented liner configurations. Several wells have experienced large water cut increases shortly after completion.
A flow profile achieved using tractor-assisted production logging sensors showed that approximately 60% of the water was produced from the bottom third of the well. An experimental technique to isolate water production in two uncemented slotted liners was employed with the use of a thixotropic annular chemical packer squeezed via coiled tubing into the slotted liner and slotted liner openhole annulus. The objective of the treatment was to shut off the bottom third of the well to reduce water rates.
Several other siliceous shale wells have been profiled, and opportunities for water isolation have been identified. Successful remediations will support the economic viability and longevity of horizontal uncemented liner completions.
In-Situ Heavy-Oils Viscosity Determination Using NMR and Conventional Logs: Application to a Real Example
Authors: Deleersnyder M. 
Published: December 2007

Abstract
Oil viscosity evaluation is a key parameter for oilfield development, particularly in heavy oil reservoirs. A robust evaluation of this parameter brings crucial informations for reservoir development and management. That is the reason why a lot of interest has been given to an estimation of viscosity thanks to continuous logs measurements and particularly NMR.
Low field NMR has shown potential for characterising heavy oils in many cases (California, Venezuela, China). Different laws have been developed where viscosity is related to an NMR parameter (T2gm, relative hydrogen index for example). One particular method (SPE 63257) is based on a property of the NMR measurement in heavy oils : NMR can not read all the signal, due to too fast relaxation times. This signal loss can be related to viscosity with a good agreement over a wide range of viscosity (from 1,000 to 1,000,000 cp).
This signal loss is given by a combination of two porosity measurements : one from conventional logs (Density-Neutron) and the other one from NMR. These two measurements are used to define an apparent hydrogen index.
This study intends first to confirm this law over a large number of samples, at different viscosities and in a second time, to apply this law on logs.
Measurements have been made on different heavy oil types from the same field. For each sample, a viscosity versus temperature law has been defined. Then, NMR measurements have been made at different temperatures. Thus, NMR measurements have been related to viscosity. A good correlation has been identified, despite the differences of the oils at stock tank conditions.
In a second time, this validated law has been used in an interpretation program for continuous viscosity estimation. A field case, using different oil types, is shown and compared to lab measurements.
As a conclusion, this methodology shows a good correlation between NMR measurements and viscosity and provides an estimation of viscosity over all the logged interval, where no fluid sample was taken.
In-situ Measurement of Rock Compressibility in a Heavy Oil Reservoir
Authors: Marchina Philippe , Brousse Alain , Fontaine Jean , Dano Christophe , Alonso Claudine 
Published: December 2007

Proposal
Compaction drive is a potentially important recovery mechanism for weakly cemented heavy oil reservoirs. In order to assess its magnitude the knowledge of the compressibility of the reservoir sands is required. However, due to the very nature of this class of reservoirs, the reliability of laboratory measurements can be questioned as the specimens are heavily disturbed during the coring process. To circumvent this shortcoming, the option of carrying out in-situ compressibility measurements becomes attractive. The use of a dilatometer, allowing the downhole measurement of the pressure-deformation characteristics of the formation, has thus been considered.
A preliminary study was carried out involving direct numerical simulations of a dilatometer test in a sand described by a Cam-Clay model. That study showed that the mechanical parameters, in particular the elastic and plastic compressibilities as well as the consolidation pressure do affect the response, thus establishing the theoretical feasibility of such a measurement.
A series of three tests were conducted in a newly drilled well in an uncemented sandstone reservoir.
By applying an inversion technique, based on an iterative finite element algorithm, it is then possible to identify the Cam-Clay parameters of the formation sands.
Abandonment of a Former Steamflood Reservoir
Authors: Slater H. J. , Nahayowski M. , Johnson M. 
Published: December 2007

Abstract
A heavy oil reservoir, namely the Lloydminster sand situated in the Delmas field in the province of Saskatchewan, Canada was developed in the 1970 to 1980 period for enhanced thermal recovery via steamflooding.
The entire field required complete abandonment and numerous innovations were employed to address the challenges that existed during the execution of the abandonment operations.
The producing wells were completed with slotted liners installed adjacent to the producing formation. In order to effectively abandon this horizon via remedial cementing it was necessary to establish communication with the area adjacent to the top of the reservoir. This was accomplished via Sanjel's abrasive jetting technique with nitrogen assist for improved penetration. Once a satisfactory feedrate with this area was achieved, then the remedial cementing activity utilizing Sanjel's low rate cement squeeze technique1 was employed. Also, surface casing vent gas flow and intermediate casing failure interventions were necessary during the abandonment operations. The cement design for all cementing activities was required to address the current reservoir temperatures as well as future concerns if this reservoir was redeveloped again incorporating advanced technologies.
This paper summarizes the entire abandonment operations highlighting the innovations employed to successfully complete the obligation.
Study and Demonstration of a Process to Extract Bitumen from Utah Tar Sand
Authors: Coleman Philip W. , Adams R. Burk 
Published: December 2007

Abstract
The successful implementation of a demonstration scale, continuous flow, modified hot water process to extract bitumen from Utah tar sands has potentially significant economic implications to the future of mineable hydrocarbon production in the United States.
In 1999 and 2000 a 20-ton per hour demonstration facility was operated to definitively test all aspects of a proposed hot water extraction process to extract bitumen from the Asphalt Ridge tar sand deposit near Vernal, Utah. Detailed analysis was performed on oil-water emulsions, solvent losses to rejected solids, recycle water quality and bitumen extraction efficiency.
Although the process concept is similar to Canadian oil sand operations, a fundamental difference between the Asphalt Ridge demonstration process and commercial Canadian operations is the production of dry tailings. This area of the process also required detailed investigation and optimization.
The demonstration facility was operated as three processes: extraction, froth treatment and refining. Although these areas were not operated in concert due to available equipment sizes, each area was operated successfully to equilibrium and for significant time thereafter to prove steady state operation.
The demonstration facility operation culminated in a 12 day, uninterrupted operation of the extraction process in September 2000.
The results of the study have concluded the demonstration process was operated long enough to achieve steady state conditions with an economic quantity of solvent losses and high bitumen extraction efficiency. Significant amounts of data were collected with which to design a full-scale extraction and froth treatment operation.