bluuebunny/crossref_metadata_2025 huggingface dataset:
Continuing Medical Education Programs for Oilfield Health Personnel: Strategy to Improve Solving Capacities On-site and Strengthen the Emergency Response Plan
Authors: Zambrano Celly John J.
Published: December 2007

In this paper, continuing medical education (CME) programs for oilfield health personnel should be understood to be any (postgraduate) process of education, training, and updating of petroleum health professionals in the field of health care (occupational health, preventive medicine, and clinical and surgical performance) aiming to improve knowledge, skills, and attitudes.

In the petroleum industry, adequate response in cases of simple medical problems or complex emergencies is essential due to extreme working conditions and environments, particularly in field scenarios.

Oil-field workers could feel confident regarding health issues, depending the real capability to solve and handle, at least initially, any health problem by their field doctors or other health personnel.

In this context, CME could play an important role in increasing their problem-solving capabilities and become an important tool that brings together occupational health topics, preventive medicine, and clinical-surgical performance issues for health teams working in extreme conditions.

Routine preventive activities could be as strong as reactive medical measures. Also, if commonly applied, oilfield companies could secure some additional values such as standardized procedures and medical field requirements (by region or country), case management, and adequate treatments for common on-site medical problems, etcetera. Currently, these requirements may vary largely among companies and contractors within the same country or region, making it difficult to operate efficiently on a timesaving basis when an urgent work is required, or securing the optimal use of resources-including the emergency response plan (ERP) - for the best health performance.

These programs could be designed centrally (for common and oilfield relevant health topics) but also should arise as local demands, considering the need to solve real problems field health personnel face in their daily duties.

So, it seems reasonable to believe that the final positive impact of CME oilfield industry programs could support more efficient, comprehensive, integrated, and holistic medical services.
Investment in Occupational Health Reduces Arctic Operating Costs
Authors: Lawrie G. , Landry L.
Published: December 2007

Schlumberger was concerned that medical costs at their Prudhoe Bay, Alaska, facilities had escalated significantly during 2000 and 2001. In March 2002, the company decided to take affirmative action and contracted Remote Services, Inc. to provide medical care to its 400 employees living and working in this remote location.

Remote Services provided two Physician Assistants (PAs) to manage the health care program. The PAs resided at the Schlumberger camp and were therefore able to provide a service on a 24/7 basis. This was a significant advantage as it enabled employees to seek preventative medical assistance after their working shift in the field.

The PAs provided the following services: trauma treatment, medical examinations, drug and alcohol testing, immunizations, legal compliance tests (respiratory testing, mask fit tests, audiometry), general health treatment (colds, viral infections, migraines), advice on diet and exercise regimes to improve overall health and stress, functional capacity testing and travel advice to staff visiting hazardous locations (e.g., malaria, West Nile disease, dengue fever).

This paper seeks to share best practices by describing how the services were used, a description of how each of the services provided a significant reduction in health exposure, the breakdown of activity in each category, and the tremendous reduction in workers compensation costs as a result of the introduction of the medical service. This paper will also describe the significant reduction in the number of staff members requiring a Medivac back to Anchorage to seek medical attention and the ensuing increase in worker morale as a result of having on-call medical attention.

The results have been very impressive and discussions with other North Slope contractors have resulted in several other companies employing Remote Services, Inc. in Alaska. The ability to set up mobile clinics in almost any environment has led to interest from mobile groups such as the seismic industry. There is scope to extend these services to any location across the world.
Skin Rashes with Oil-Base Mud Derivatives
Authors: Cauchi G.
Published: December 2007

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

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

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

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

In 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

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

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

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

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

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

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

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.
Economic Evaluation of Treating Oilfield Produced Water for Potable Use
Authors: Patrick B. , Tsang P. E. , Christopher J. , Martin P. E.
Published: December 2007

Conventional opinion has often viewed produced water as a byproduct from oil production. Disposal of this water is an expense every treatment facility must contend with as long as their wells continue to produce. This issue can become a serious logistical or environmental problem for fields with limited disposal capacity or that generate produced water with poor water quality.

Instead of discarding the water as waste, advances in membrane water treatment technology can allow economical treatment of water for potable consumption. Placing this water to productive use may not completely eliminate daily wastewater disposal. However, it will drastically reduce the disposal volume, possibly freeing up other resources. This concept shifts the paradigm for produced water, transforming its image from what seemingly is a costly waste to possibly a valued commodity.

This paper will present a conceptual design for a 50,000 BPD integrated membrane filtration plant capable of handling typical oilfield produced water. Included will be an evaluation of capital and operating & maintenance costs. A discussion on the marketing potential for this water as a new potable or irrigation water source will also be presented by comparing its economics against conventional surface water or seawater desalination treatment.
Sand Erosion in Cold Heavy-Oil Production
Authors: Yalamas T. , Nauroy J.-F. , Bemer E. , Dormieux L. , Garnier D.
Published: December 2007

Ensuring quantitative prediction of eroded sand volume is a major challenge for companies, which seek to conduct effective sand management. This is particularly a key point for Cold Heavy Oil Production With Sand.

IFP has been studying the geomechanical aspects of heavy oil cold production for several years from both the experimental and theoretical points of view [Deruyter & al., 1998], [Nauroy J.-F., 1999]. While experimental studies of sand erosion are mostly based on linear flow through cylindrical cells [Tremblay & al., 1995], IFP has designed a special oedometric cell to simulate a radial flow around a well drilled in an unconsolidated sand reservoir.

The current device allowed to observe two types of erosion figure under CT-scan, defined as "cavity" or "spread erosion". Two main key parameters governing erosion have been identified.

Dimensional analysis shows that CHOPS in situ conditions should lead to a "cavity" type erosion. Various theoretical models describing sand erosion and mixed sand/fluids flow have been investigated. An algorithm allowing to predict the formation of a cavity has notably been defined and already validated for a 1D numerical modeling. A 2D numerical modeling is in progress.
Effects of CO2 and CH4 Addition to Steam on Recovery of West Kozluca Heavy Oil
Authors: Bagci A. S. , Gumrah F.
Published: December 2007

The physical models, cylindrical tube (1-D) and rectangular box (3-D), were used to examine the effects of simultaneous injection of CO2 and CH4 together with steam on the recovery of 12.4 °API gravity heavy oil mixed with unconsolidated limestone.

The results of 18 experiments showed that gas-steam injection was a promising technique. Gas/steam ratio was found to be a significant factor among the studied variables in heavy oil recovery. The optimum gas/steam ratio that maximized the recovery was about 9.4 cc/cc for both steam-CO2 and steam-CH4 processes in one-dimensional model. It was 8.7 cc/cc for steam-CO2 process in 3-D model.

At 1.5 pore volumes of steam injected; the oil recoveries were 66.5 % of OOIP for steam-CO2, 60.4 % of OOIP for steam-CH4 and 50.9 % of OOIP for steam alone tests in 1-D model and they were 49.9 % of OOIP for steam-CH4, 36.2 % of OOIP for steam-CO2 and 21.7 % of OOIP for steam alone tests in 3-D model. The lower residual oil saturations were obtained in gas-steam injection tests, compared to the values obtained with steam alone.

The injected non-condensable gas created a permanent gas phase across the top of the model therefore heat arrived to the producing well earlier than steam alone test. The depression of steam temperature was also observed due to the presence of non-condensable gas.
Expanded Uses of Nitrogen, Oxygen and Rich Air for Increased Production of Both Light Oil and Heavy Oil
Authors: Kuhlman Myron I.
Published: December 2007

Both light-oil air injection (LOAI) and nitrogen injection have received considerable attention recently due to several successful LOAI projects and the building of massive nitrogen generation plants for offshore EOR. This paper explores the advantages of combining the best of both technologies via cogeneration of nitrogen and rich air for use in adjacent reservoirs.

Rich air (30% to 40% oxygen) can be an alternative to carbon dioxide injection just as air injection is generally practiced where carbon dioxide is not available. Rich air is the byproduct of nitrogen generation and has approximately the same price as nitrogen, yet it will recover more oil because of the higher solubility of the carbon dioxide that is produced by in-situ oxidation of the oil.

Not only can the rich air be used for light-oil production, but also it can be a more efficient way to produce energy from heavy-oil through wet combustion in deeper reservoirs. Examples contained herein illustrate how nitrogen and rich air can be used in both light- and heavy-oil reservoirs.
Disposal of Carbon Dioxide, a Greenhouse Gas, for Pressure Maintenance in a Steam-Based Thermal Process for Recovery of Heavy Oil and Bitumen
Authors: Law David H.-S.
Published: December 2007

The world is moving towards a carbon constrained economy and there would be pressure to reduce greenhouse gas (GHG) emissions. The steam-based thermal processes are energy intensive and hence, high carbon dioxide (CO2), a greenhouse gas (GHG), emissions. There are potentials for the reduction of CO2 emissions by capturing and disposal of CO2 for pressure maintenance during the later stage of these thermal operations. This paper describes the numerical investigation on the feasibility of using CO2 for pressure maintenance during a steam-assisted gravity drainage (SAGD) wind-down process in an Athabasca bitumen reservoir in Northern Alberta, Canada.

It is found that SAGD wind-down process with CO2 injection is feasible although oil recovery performance is slightly sacrificed. The oil recovery performance during the wind-down period with pure CO2 injection is slightly better than those with other gas injections such as flue gas (i.e., a mixture of nitrogen (N2) and CO2) and pure N2 mainly because CO2 acts as a solvent in reduction of the bitumen viscosity.

From a GHG storage point of view, CO2 storage capacity of approximately 2 × 107 sm3 (or 37,244 tonne) in a single Athabasca-type SAGD pattern with dimensions of 100 m wide, 500 m long and 25 m thick can be achieved. CO2 balance indicates that CO2 stored during SAGD wind-down processes is less than the CO2 emitted from steam generation during the initial SAGD period. However, "CO2 credit" in the order of 10,000 tonne can still be claimed in a single SAGD pattern because using CO2 as steam substitute during the wind-down process results in less CO2 emission compared to continuously operating the SAGD process.

Recently, numerical prediction in this study has been validated qualitatively by the experimental observations of SAGD pressure maintenance from a low-pressure/low-temperature CT experiment and a high-pressure/high-temperature 2-D experiment conducted at the Alberta Research Council (ARC).
Characterization of Water Injection in Low Permeable Rock Using Sandstone Micro-Model
Authors: Sun Wei , Qu Zhihao , Xian P. R. C. , Tang Guo-Qing
Published: December 2007

Visual micro-model technology has been applied to investigate multiphase flow in porous media because it allows watching the fluid flow clearly under a microscopy. However, most micro-models are made up using glass media. A sandstone micro-model (SMM) manufactured from thin sandstone chip directly was introduced and applied in the study of water injection in low permeable rock. To make the sandstone micro-model, a selected core plug was carefully machined into a chip with a thickness of about several hundred micrometers. The sandstone chip was then sandwiched in two glass plates using a specific cementing process. The main improvement for this kind of micro-model is that it preserves the original pore structure, clays, cements, and pore surface properties.

Total 18 sandstone micro-models with permeability from 1-10 md were used for displacement test at room temperature. The results show that the water injection in the weakly oil-wet to neutral-wet sandstone micro-model is dominated by the injection pressure. At low injection pressure, the water can only enter large pores that have a high conductivity. Large amount of pores is not flooded by water. When the injection pressure was increased, water is forced into some small pores to displace oil. However, heterogeneous properties of the porous media can cause a bypass flow, resulting early water breakthrough and low water displacement efficiency. We also found that oil recovery is proportional to the permeability of the model, suggesting the pore conductivity is the key to the water injection efficiency.

This study also shows that sandstone micro-model provides visual and realistic results that reveal the microscopic mechanism of water injection the target reservoir. However, visibility is less compared to a glass micro-model. Thus, the combined results from both sandstone and glass micro-model are more valuable.
A Study of Heavy Oil Solution Gas Drive for Hamaca Field: Depletion Studies and Interpretations
Authors: Satik Cengiz , Robertson Carlon , Kalpakci Bayram , Gupta Deepak
Published: December 2007

We present results of a systematic study performed to investigate heavy oil solution gas drive process for Hamaca field in Venezuela. The ultimate goal of this study is to provide the data needed for Hamaca reservoir simulation studies. The study included a series of rock and fluid property measurements, and several carefully performed depletion experiments. Supplemental experiments using PVT cells and ideal porous media were also conducted to aid in the analysis of the depletion experiments.

For this study, single-phase live oil samples from Hamaca Field were used. Fluid characterization tests were performed, including GOR, viscosity, density, compositional measurements and other PVT experiments. Average properties of the live oil used were GOR of 96 scf/STB, bubble point pressure of 1020 psia at 125 °F and viscosity of 1650 cP at reservoir conditions. In addition, several flow experiments were conducted using the live oil to elucidate so-called "foamy oil" behavior by obtaining rheological data at above and below thermodynamic bubble point.

Depletion experiments were conducted at reservoir conditions using field core and oil samples from Hamaca Field. Tests were performed at constant depletion rates from 0.25 psi/hr to 43 psi/hr to cover the flow regimes, which may be occurring at different distances from the wellbore. A CT scanner was used to observe the distribution of gas saturation at various points during the depletion tests. Critical gas saturation values ranged from 8 to 15%. Depletion rate did not have significant effect on the critical gas saturation. Gas-oil relative permeability curves were calculated using a new technique based on effluent density measurements done during the depletion experiment. Calculated gas relative permeability curves appeared to be suppressed, in the range of 10−10 to 10−5.
Applications of dynamic gridding to thermal simulations
Authors: Christensen J. R. , Darche G. , Déchelette B. , Ma H. , Sammon P. H.
Published: December 2007

This paper describes a new technique to decrease the computational times of thermal simulations. Effectively, thermal processes are based on the displacement of a thermal front (combustion front, steam chamber interface), around which most fluid flows will take place. Thus, we propose a dynamic gridding approach, to keep a fine scale representation around the thermal front, and a coarser grid away from the front, thus leading to cheaper computations.

We will first describe the principles of this dynamic gridding. Simulations will start with an original fine grid, but will reamalgamate its cells, while keeping some regions (for example around wells) always finely gridded. The gridding will then identify the moving front through large gradients of specific properties (temperatures, fluid saturations and compositions). In the front vicinity, it will de-amalgamate the originally amalgamated cells, and later on re-amalgamate them once the front has passed. Amalgamated cells are assigned up-scaled properties, this upscaling being based upon classical averaging techniques.

We will illustrate this dynamic gridding technique with simulation examples, as it has been successfully implemented in a thermal simulator, STARS, a product of Computer Modelling Group Ltd (CMG). Using examples on combustion and SAGD simulations, we will show that it can divide the CPU time of thermal simulations by a factor of 2 to 3, without loss of accuracy.
Subsurface Challenges in Reservoir Modeling for Hamaca Project
Authors: Acharya U. K. , Kent A. , Betancourt D. , Waite M. W. , Tankersley T. , Johansen S. , Robertson C.
Published: December 2007

Hamaca project is a large resource base producing Extra Heavy Crude Oil from the Orinoco belt of Venezuela. The project is operated by Petrolera Ameriven, an operating agent owned by ConocoPhillips, ChevronTexaco, and Petróleos de Venezuela, S.A. (PDVSA). Primary production started in September 2001 from a few horizontal wells; development drilling will continue over the next 34 years to maintain a production plateau of 190,000 bopd of cold production.

The subsurface challenges involve building a representative reservoir model on a very fine scale to honor a very heterogeneous system over a large area, wide variations in temperature across the field and their effect on oil viscosities, vertical and lateral variations in oil properties and fluid pressure, upscaling the model sufficiently to be capable of running the dynamic model on available computer hardware and software. The model is calibrated using the short Hamaca production history (less than 2 years), and is then used to predict the performance of development scenarios containing hundreds of horizontal wells to be drilled in the future.

The paper discusses the challenges of selecting suitable modeling methodologies, of matching the limited historical production data, of modeling the influence of production in adjoining fields, of populating the model with hundreds of wellpaths for future horizontal wells, and of conducting sensitivity analyses to evaluate the effect on production forecasts of uncertainties in some key reservoir parameters.
Characterization of Rock Heterogeneity Using Fractal Geometry
Authors: Li Kewen
Published: December 2007

There have been three main models applied to infer fractal dimensions of reservoir rock from capillary pressure curves measured by mercury intrusion. In this study, fractal dimension was used to characterize the heterogeneity of rock quantitatively. The three fractal models were derived theoretically and found to be interrelated. Capillary pressure curves of different rock samples were measured using a mercury intrusion technique. The values of fractal dimension were calculated using the three fractal models and the results were compared. The values of fractal dimension calculated from two models were almost the same and ranged from 2 to However the fractal dimensions calculated using the other model were different and ranged from 1 to 2. It was found that the Brooks-Corey capillary pressure model did not work for all of the core samples studied but the fractal models work satisfactorily in all cases. The fractal approach was verified qualitatively using frequency graphs of pore size distribution of the rock samples.
Application of Stress-Dependent Rock Properties in Reservoir Studies
Authors: Vassilellis George D. , Jones Stanley C.
Published: December 2007

Jones1 previously developed smooth, non-linear equations for fitting permeability, PV, or porosity data at multiple net hydrostatic confining stresses. The present paper supplements the original by illustrating steps required to convert these measurements into curves for uniaxial strain conditions. The concepts of specific pore volume and specific bulk volume are introduced. These dimensionless values are independent of sample size, and are more useful than pore volume or bulk volume when comparing samples. The latter is useful for subsidence calculations.

An averaging technique for the reduction of normalized PV, porosity, or permeability with increasing net stress is also demonstrated for samples from a particular lithology. Samples that do not fit the general trend are easily identified, and can be excluded from averaging if desired. Studies in California reservoirs suggest that stress-related permeability reduction correlates with corresponding reduction in porosity better than permeability correlates with porosity.
A Simple Model for Predicting Heat Loss and Temperature Profiles in Thermal Injection Lines and Wellbores With Insulations
Authors: Guo Boyun , Duan Shengkai , Ghalambor Ali
Published: December 2007

Accurate predictions of heat loss and temperature profile in thermal injection lines and wellbores are essential to designing and evaluating thermal operations. Although some sophisticated computer packages are available for such purpose, their accuracies suffer from numerical treatments and model-building skills of inexperienced users. A simple-and-accurate analytical heat transfer model is highly desirable.

This paper presents three analytical heat transfer solutions for predicting heat loss and temperature profiles in thermal-insulated flow conduits. The three solutions consist of one steady state flow solution and two transient flow solutions. The two transient flow solutions are for start-up mode and flow rate change mode (shutting-down is a special mode where the flow rate changes to zero). Capability of the analytical model is investigated using a data set that is representative to a typical case of liquid flow in a small-diameter thermal pipeline. An application example is illustrated where the model-calculated temperature profile is used to identify the possible interval of asphaltene deposition in an oil well. The mathematical heat transfer model can also be used for predicting temperature distribution in offshore pipelines.