bluuebunny/crossref_metadata_2025 huggingface dataset:
Technical and Economic Analysis of the Downhole Scale Risks and Uncertainties for Subsea and Deepwater Field Developments
Authors: Graham G. M. , Collins I. R. , Johnson T. J.
Published: December 2007

Scale control is conventionally achieved by the use of chemical inhibitors, introduced to the production system either by squeeze treatment into the reservoir or continual injection into the well. However, as new field developments encounter more challenging production environments or when the associated economic impact of chemical intervention is large (e.g. subsea completed wells with poor chemical placement by bullhead treatments, or limited access to wet subsea wellheads), other methods of scale control such as sulfate removal must be considered during the front end engineering design (FEED) stage for the development. However, the final selection of a fields scale management strategy relies on various technical and economic factors which themselves are controlled not just by the severity of the anticipated scaling regimes but also on the proposed field development plan. For subsea completed wells, especially those located in deepwater, the initial field development concept and drainage strategy can have a significant bearing on the costs ultimately associated with various scale management strategies and can, in extreme cases, significantly reduce the Net Present Value (NPV) of the project. The decisions taken at the concept selection stage for scale management in such environments are therefore crucial to the success not only of the chosen scale management strategy but also to the fields economic viability.

This paper reviews the various challenges associated with scale formation and control in subsea and deepwater environments and the impact that different field design scenarios may have on the potential success of various scale management options. In particular, the paper will focus on technical, economic and risk-based analysis conducted for a number of new and proposed subsea field developments with different scaling challenges. The options for scale management in selected subsea and deepwater developments including examples from the North Sea (Shallow water), offshore Angola, and Gulf of Mexico cases will be reviewed. The impact of the various risks and uncertainties associated with determining the severity of the scale challenge (including the quality and source of initial water compositions, the accuracy of simulation tools used for the prediction of future scaling challenges prior to field production, the ability to effectively squeeze treat and place scale inhibitors into particular wells and the potential for changes in the field drainage strategy) are assessed in terms of the total costs associated with particular cases. In summary, the paper will describe the decision process used at the pre-FEED stage to determine a field scale management strategy for different development concepts. Detailed economic analysis of different options considered in recent field cases will be presented to support the different strategies adopted.
In-Situ Uranium Leach Mining: Considerations for Monitor well Systems
Authors: Durler David L. , Bishop Author L.
Published: December 2007

Monitor wells are placed around an in situ leach mine to alleviate the potential for groundwater degradation. Such monitoring systems are the result of regulatory requirements or theoretical hydrologic concepts, irrespective of geologic anisotropies. Certain geologic factors can influence the groundwater regime and, therefore, markedly affect the adequacy of groundwater monitoring systems.
Deep Mineral In-Situ Solution Mining
Authors: Hunkin Geoffrey G.
Published: December 2007

Uranium exploration drilling depths for western sandstone type deposits have increased from a maximum of 60 m (200 ft) to over 600 m (2000 ft) in the past 25 years. Recent test wells have exposed favorable depositional conditions and mineralizations below 1350 m (4500 ft). This paper describes engineering analysis and bench testing performed in order to estimate exploitation processes appropriate for these deep occurrences.

Physical-chemical laws show that the efficiency of uranium dissolution increases with pressure. The key factor is the square root of the partial pressure of oxygen, which controls the oxidation of four valency uranium to the six valency soluble condition. As depth increases operating pressures, so control of high oxidation potentials becomes easier and less expensive. Cost of all reagents, including complexing chemicals, is reduced without risk of re-precipitation, due to the decreased pH sensitivity.

Inter-well spacings are shown to increase rapidly, while maintaining the same permeability/flow rate/differential pressure relationship. The mass of recoverable uranium tributary to an operating well increases much more rapidly than does the incremental cost of deeper wells.

Environmental factors should become of reducing importance as depth increases due to the remoteness of the production area from potable, exploitable groundwater supplies.
Operating Experience in the Recovery of Uranium at the Pawnee and Zamzow Sites
Authors: Annamalai Velu , McGarvey Francis X.
Published: December 2007

IEC Corporation is presently recovering uranium by in-situ leaching or solution mining technique at the Zamzow site, and completed its production at the Pawnee site. An oxidative lixiviant with ammonium carbonate and hydrogen peroxide is injected into subsurface ore strata according to a defined wellfield pattern. The resulting uranium-enriched leachate solution is pumped out of the ground and brought to the recovery plant. This solution is filtered first and then the uranium is recovered by an ion exchange process. The final product of yellowcake is produced by steam precipitation and vacuum drying. The uranium-free barren solution is re-injected into the orebody after adding the necessary make-up chemicals.

Several problems related to ion exchange performance were observed during the initial startup of the Pawnee site. These included fouling with polythionates and oxidative attack on the resin structure. Cooperative studies between IEC Corporation and Sybron Corporation led to the selection of a resin with increased resistance to oxidative attack. Modification of the feed solution chemistry resulted in control of the polythionate fouling and also in reduction in uranium losses. These findings were also applied to the second site operation where acceptable performances have been experienced for the past two years.

The Pawnee site, a small orebody, has been worked out and a site restoration program has been under way for over a year. Methods for handling above ground wastes are discussed and approaches to the control of underground ground water contaminants are outlined. Lessons learned at Pawnee are discussed in light of restoration of future sites.

The Zamzow site has been in full production since July 1978. General plant practices and economics are outlined and future recommendations on process modifications suggested.
CO2 Corrosion in Bromide and Formate Well-Completion Brines
Authors: Leth-Olsen H.
Published: December 2007

Corrosivity data for halide and formate well brines that have been acidifies as a concequence of influx of large amounts of acid gas has been requested.

The well materials C-steel, standard 13%Cr steel and Super 13%Cr steel were corrosion tested in potassium formate and CaBr2 brines acidified with CO2 gas, simulating a well situation with influx of acid gas. The acidification resulted in an initial accelerated corrosion of C-steel in both solutions, reduced to low levels by time due to formation of a protective iron-carbonate layer. Both C-steel and standard 13%Cr steel were attacked by severe localised corrosion in the bromide brine, whereas only limited general corrosion was developed in the formate brine. Super 13%Cr was uncorroded in both brines.
Thermodynamic Predictions of Scale Potential, pH, and Gas Solubility in Glycol-Containing Systems
Authors: Kaasa B. , Sandengen K. , Østvold T.
Published: December 2007

Transportation of hydrocarbons and water in long subsea flowlines from satellite fields to a platform or to shore results in new challenges to control hydrates, corrosion and scale. As the fluids cool down, water will condense and gas hydrates will form unless an inhibitor such as mono ethylene glycol (MEG) is present. The presence of MEG changes the thermodynamics of the aqueous phase and lowers the solubility of most salts. MEG also changes the pH, the gas solubility and the acidity of CO2. Controlling scale and corrosion in such systems requires good control of pH, salt solubility, gas solubility and the effect of MEG on these parameters. This work presents a model that can accurately predict pH, scale potential, gas solubility and salt solubility in systems with MEG concentrations from 0-95wt%. The model is based on a large amount of experimental data in MEG containing systems, both from the literature and from the present work. With the model it is possible to accurately predict pH and scale potential as function of pressure, temperature, composition of water and hydrocarbon phases and MEG concentration.
Corrosion Resistance and Long-Term Reliability of Super-Austenitic Alloy 27-7MO for Use as Expandable Pipe
Authors: Chitwood G. B. , Eisinger N. C. , Puckett B. C.
Published: December 2007

In today's competitive oilfield environment, end-users are faced with choosing the lowest-cost material that meets the technical and environmental needs of the application. With field development expanding into deeper, more corrosive environments, corrosion-resistant alloys (CRAs) must be used.

In this paper, the discussion will investigate CRAs and the added burden of maintaining economic efficiency in corrosive environments requiring sand control ― more specifically, materials for expandable sand-control systems. For expandable applications, materials must compete with existing non-expandable lower-cost commodity-type screen materials. 13Cr, for example, is the first choice CRA material for the base pipe in conventional sand screens. Although 13Cr is one of the least costly of the CRAs and provides the necessary corrosion resistance in mild H2S environments under a variety of chloride/temperature conditions, it lacks the ductility needed for 20 to 25% expansion as a solid-expandable. Austenitic stainless steels such as 316L (UNS S31603) have the needed ductility for expansion, but with their low resistance to Stress Corrosion Cracking (SCC) may be insufficient for severe-service applications.

Thus, a need for an alloy that can be expanded while maintaining corrosion resistance is required. Furthermore, to prevail in this very competitive arena, the material must offer a cost-effective alternative to standard 13Cr and expanded S31603 pipe. The basis for this study involves measuring the SCC resistance and predicting the mechanical behavior of higher-strength corrosion-resistant super austenitic alloy 27-7Mo (UNS S31277). Slow strain rate (SSR) tests, pitting and corrosion tests, as well as U-bend tests are used to explore and compare environments where S31277 and S31603 can offer the most economical solution for expandable sand control products in corrosive conditions.
Application of CE and CE-MS to Assay Corrosion Inhibitors Used in Well-Stimulation Treatments
Authors: Al-Katheeri M. I. , Nasr-El-Din H. A.
Published: December 2007

Well acidizing treatments are conducted to enhance rock permeability, remove or bypass formation damage. During field applications, corrosion inhibitors are extensively used, among many other additives, to protect well tubulars against acid attack. The inhibitors are complex mixtures containing: quaternary salts, acetylenic alcohols, surfactants, solvents and impurities. Therefore, several analytical techniques and instruments are needed to characterize these compounds.

Capillary electrophoresis (CE) is a rapid and reliable analytical separation technique. It has significantly improved over the last two decades to include a wide range of analytical applications, such as: food, pharmaceutical and biomedical industries. Coupling CE to universal detectors, such as Mass Spectrometry (MS) can boost the analytical ability of this instrument in qualitative and quantitative applications.

In a previous work (SPE 58801) the authors adopted a CE technique to monitor the level of key oxygenated compounds in acid additives that are also used in deep, hot and sour gas wells. In the present work, the use of capillary electrophoresis-mass spectrometry (CE-MS), chromatographic and spectrometric techniques, to identify key nitrogen compounds in acid corrosion inhibitors was investigated. The inhibitors were selected from several commercial products that are commonly used in the field.

Capillary electrophoresis was also applied for quantitative measurement of the inhibitor's level in well fluids, based on the response of its key nitrogen compounds. A linear relationship was obtained for the inhibitors of interest. The cation selected was a quinoline-based quaternary salt. This cation was detected down to inhibitor's level of 0.023 wt% with an analytical precision of less than 10%.

The CE technique was used to determine the level of the corrosion inhibitors during acid fracturing treatments of deep gas wells.
Naphthenate Control: Is Acetic Acid Injection the Answer?
Authors: Bretherton N. , Smith R. , Keilty G. , Ubbels S.
Published: December 2007

Naphthenate precipitation is encountered when the naphthenic acids, present in acidic crude oils, interact with calcium and, to a lesser extent, other metal ions that are present in connate waters. Precipitation is often associated with a rise in solution pH. It can cause severe problems during the separation of oil and water, forming very stable emulsions and/or insoluble deposits in separators or crude dehydration/desalting vessels.

Acetic acid injection is widely used to inhibit naphthenate precipitation and remove calcium from crude oils. This has significant implications for the integrity of the process pipework and vessels. The impact of acetic acid on the corrosion of carbon steels under typical oilfield conditions is discussed. Laboratory and field data are presented to demonstrate the impact of acetic acid on corrosion rates.

A variety of mitigation options are discussed, including the impact of acetic acid on corrosion inhibition. These include the use of novel surfactants to inhibit calcium naphthenate precipitation. This type of naphthenate inhibitor has been shown to provide effective naphthenate control in the absence of any pH reduction, eliminating the detrimental effect of acetic acid injection on process pipework and vessels.
Federal Land Availability an Industry View
Authors: Nanz Robert H.
Published: December 2007

I appreciate the opportunity to address this distinguished audience on the availability of Public Land, a subject which is critical to the future of this nation. It's a highly controversial matter, as you know, and I should say at the outset that my remarks will include criticism of the Federal Government. My criticisms may not surprise our previous speaker inasmuch as I have expressed views on this subject in twelve (12) visits with the Departments of Interior and Energy and in ten (10) Congressional or BLM Hearings over the past six years.

An outline of my remarks is shown in Figure #1. To set the stage I would like to emphasize the long-term need for oil and gas in the U.S., the large potential that exists for new discoveries in the U.S., and the significance of Federal Lands inasmuch as the greatest potential for new discoveries is on those lands. This will be followed by a brief discussion of the problems related to the availability of Federal Lands and what can be done about them. Finally, I will present our estimates of additional volumes of oil and gas which could be produced from an acceleration of leasing and permitting on the Alaskan OCS.

Our latest forecast of U.S. supply and demand is shown in Figure #2. To maintain a healthy economy with a rising population, we foresee an increasing demand as shown. We estimate that about one-half of the oil and gas production shown in 1990 must come from new discoveries. This will require very aggressive exploration and development on all fronts. Coal production must also be accelerated but that is a whole separate subject. Geothermal, solar and synfuels will have little impact by 1995. My point here is that we will need all the domestic production we can get in order to minimize the need for increased amounts of import.
Forecast of Supply and Demand and Price for NGL
Authors: Hubbard Robert A. , Campbell John M. , Campbell John M.
Published: December 2007

Summarized herein is an improved approach for forecasting supply, demand, and price for natural gas liquids. No new fundamental principles are espoused. Rather, what has been done is to combine proven economic/engineering tools through team effort to produce more reliable forecasts for use in business decisions. An econometric approach is used, but the variables used are governed by plant process characteristics, marketing factors and the distribution of future supply.
Interpretation of Multi-Hydraulically Fractured Horizontal Wells in Naturally Fractured Reservoirs
Authors: Bettam Y. , Tiab D. , Zerzar A.
Published: December 2007

Horizontal wells are thought to be necessary in formations with low-permeability to increase the recovery and reduce the risk of drilling a dry hole. The horizontal well may cross natural fissures. Although hydraulically fracturing horizontal wells in such formations is a risky job, it may be necessary in order to achieve commercial production. This is especially true for naturally fractured gas reservoirs with matrix permeability in microdarcies and where natural-fracture network does not contribute considerably to the flow from the reservoir into the wellbore.

This study investigates the transient pressure behavior of a multiply fractured horizontal well (MFHW), as well as the long time performance of such a completion in an anisotropic naturally fractured reservoir of infinite extent.

Combining boundary element method and Laplace transform, single-fracture solution is considered first as it constitutes the core part of the multiple-fracture model. Then, a solution to multiply fractured horizontal wells is presented, which assumes fractures of distinct properties, it allows for unequal spacing between fractures, and permits the perforation of portions of the interval between fractures. Furthermore, it allows the juxtaposition of any number of perforated intervals and any number of fractures.

The pseudo-steady state is considered to account for the fluid transfer between the matrix blocks and the fracture network.

Due to its simplicity, accuracy, and reliability, procedures for using the new technique referred to as "Tiab’s Direct Synthesis" have been developed to analyze the transient pressure and pressure derivative behavior of a MFHW in a naturally fractured reservoir. Individual fracture properties can be determined if individual flow rate contributions are measured, otherwise an average conductivity and half-length is determined.
Reserve Based Financing - Specific Requirements and Alternatives
Authors: Mintz Forest
Published: December 2007

Many oil and gas producers find it advantageous to borrow against the value of their hydrocarbon reserves. This paper considers the requirements for a reserve based loan and the calculations that a bank would perform to arrive at a loan amount. Three of the most common loan structures, i.e. a term loan, a production payment, and a revolving credit/term loan will be discussed. A typical outline for each type of loan is presented. Finally, a comparison of major considerations in the three financing techniques is shown.
Desulphurization of Gas and Corrosion Control in Pipelines
Authors: Leventis Eugène , Grulet Louis
Published: December 2007

The need to develop a national source of energy linked with gas contracts specifications, environmental and corrosion problems have brought SNEA to develop its own gas desulphurization process.

This had lead to a big sulphur production and a new source of revenues, as well as licence selling.
Geochemistry of Reservoir Fluids as a Unique Approach to Optimum Reservoir Management
Authors: Slentz Loren W.
Published: December 2007

Thousands of analyses of oils and formation waters have established the applicability of compositional data to such problems as determining reservoir continuity, evaluating workovers and identifying extraneous production. Interpretation and presentation of such data can be enhanced through use of computer technology. Star diagrams and cluster analysis are two examples. The value of geochemistry is illustrated in case histories from California, the U.S. Gulf Coast and the Middle East.
Distribution of Sulfur Compounds in Arab Crudes
Authors: Ali Mohammad Farhat , Ul Hasan Misbah , Saleem Mohammad
Published: December 2007

The chemistry of sulfur and sulfur compounds present in petroleum is of vital interest to petroleum technologists. This paper describes the results of an analytical study of four Arabian crude oil distillates for the type of sulfur compounds present in them. Each crude oil sample was distilled up to 350°C to separate it into various fractions. The concentration of sulfur compound groups present in each fraction was determined.
Large Scale Waterflooding in the Yibal Shuaiba Chalk Reservoir, Oman : Field Performance and Simulation Studies
Authors: Grant Alan J.
Published: December 2007

Large scale waterflooding in the Yibal Shuaiba chalk reservoir in North Oman has been chosen as the optimum secondary recovery technique. Started in 1972, this scheme is still being extended and will eventually include a combination of central pattern flooding and peripheral flooding. This paper contrasts the initially envisaged development as predicted by simulation studies with the actual history of the field and, in particular, the relevance of the former is critically reviewed.
Foamed Cement – A Cement With Many Applications
Authors: Davies David R. , Hartog Jan J. , Cobbett James S.
Published: December 2007

Foamed cement formulations have been developed which show promise for application: –as a cheap, economical and effective light-weight cement for application in formations with a low fracture gradient. Use of normal cements in these would cause the breakdown pressure in these weak formations to be exceeded, resulting in incomplete cement columns and inadequately supported casings. The density of the foamed cement may be easily adjusted in order to minimise cement losses while foamed-cement strength is being maximised.–as a means for curing lost circulation in areas where cavernous vugs cannot be plugged by conventional lost-circulation materials. Plugging by conventional cement also fails, since it flows to the bottom of the vug owing to its greater density. The use of a (thixotropic) foamed cement of density matched with that of the fluid in the vug will ensure that this gravity segregation no longer occurs.–as an expansive cement which will ensure good zonal isolation in zones where gas channelling behind the casing and pressurised casing annuli are frequently encountered. The expansive nature of foamed cement - owing to the gas contained in the cement - ensures that loss of hydrostatic head exerted by the cement column can be (partially) compensated for by expansion of the cement.

Small-scale and large-scale laboratory tests showed that stable cements could be mixed and pumped. This was confirmed during a subsequent field test. This field trial was carried out using standard oilfield equipment without requiring the presence of specialists.
Effect of Temperature on Formation Resistivity of Some Saudi Reservoir Rocks
Authors: Dolka Mahmoud El-Awady
Published: December 2007

An experimental study was made to investigate the effect of temperature on formation resistivity under Saudi reservoir conditions. Representative sand-stone and lime-stone cores were used. The resistivity was measured in a cell using the four electrode method and with 60 Hz current. The cell is kept in a jacket to maintain temperature, and displacement of fluids from plugs is allowed. The temperature range used was from 30 to 90°C, (86-194°F). Water salinities used were between 50,000 to 200,000 ppm Nacl.

Results indicate that for sand-stone cores, formation resistivity decreases with temperature increase. The saturation exponent also decreases with temperature, and the rate of decrease depends upon shale content of the cores. The value of n ranges between 2.1 and 2.2 at high water saturation and may become as low as 1.7 at low water saturation.

Limestone cores studied did not show marked change in apparent formation resistivity factor or saturation exponent with temperature change. The value of saturation exponent for the cores studied was in the range of 1.9.
Use of Glass Reinforced Epoxy Resin Tubing in Oman
Authors: Archibald Robert M. , Bulstra Robert A.
Published: December 2007

A total of three strings of glass fibre-reinforced epoxy resin (GRE) threaded and coupled tubing has been installed on a trial basis in the Natih and Fahud fields in order to determine if the known corrosion resistance of GRE is matched by a long term mechanical reliability. After some eighteen months exposure to normal operating conditions, the tubing in two water-injectors continues to give satisfactory service. The tubing in a gaslifted oil producer however failed.
Field Application of In-Situ Nitrogen Gas Generation System
Authors: Davies David R. , Richardson Edwin A. , Antheunis Dan
Published: December 2007

Nitrogen gas is used in a wide variety of well treating operations. The only source of nitrogen gas which has been available until recently is from vaporised liquid nitrogen. It has now been shown possible to generate large quantities of nitrogen gas from aqueous salt solutions. Use can thus be made of conventional pumping and blending equipment for carrying out these treatments; in place of the liquified nitrogen storage facilities and the high-pressure, cryogenic pumping and vaporising unit conventionally required.

This paper examines the potential of the in-situ nitrogen-gas generation system from a practical point of view. It is intended to be an aid to petroleum engineers in deciding as to whether the system will be useful for their particular problem.

The ‘chemical’ boundaries (e.g. maximum amount of gas generation, practical gas generation rates, etc) of the system are discussed. Applications - some of which are field proven - which illustrate the utility of the system are given. One general application is the reduction of the hydrostatic head of the fluids in the wellbore - either as a ‘single shot’ or as a continuous process - so as to put the well on production. This also has specific applications - such as an aid to drill stem or production testing in heavy oil reservoirs, back surging, etc.

Some of the design considerations for planning a field job are presented.

The field test experience to date is discussed. Finally, the results of some research (the need for which was highlighted by these field tests) on corrosion inhibitors is reported.
Deep Hole Prospecting - Role of the Consultant
Authors: Boyd Foy W.
Published: December 2007

The nation's new energy mandate for exploratory searches below fifteen thousand feet coincides with a serious shortage of top echelon deep hole drilling specialists. The consultant, one who provides professional advice or services, fills the gap in the "brain drain" of the last 15 or 20 years. In making decisions, the consultant very likely uses a quick formula dealing with Cost Risk Analysis and Planning, Communication and Teamwork to arrive at a successful completion. His duties are never-ending. He expects much of himself, and delivers. As the available source for the knowledge and experience current conditions demand, the consultant may be the industry's best immediate hope.
Acidizing Low Pressure Gradient Wells Using Carbon Dioxide
Authors: Chapman Ron
Published: December 2007

The problem of stimulating wells that have a low bottom hole pressure gradient has been one that the industry has met with mixed results over the years. For the purpose of this paper, low gradients are anything less than a 0.35 psi-ft. gradient. We have picked this number since under normal stimulation conditions, few wells will flow their load back without some means of artificial lift. Clearly, mechanical means of lift have been historically the more widely used, the most successful, but intrinsically the least attractive of all alternatives. This is, of course, due to the inherent mechanical risks, depth limitations, and pressure considerations of bringing a well back in. To simplify, swabbing in a gas well at 8000′ with 2000′ psi bottom hole pressure (0.25 gradient) is at best a delicate chore. Therefore, we have for years attempted to use other means of providing the energy for these wells to be able to come back on their own.

Mixing nitrogen with various fluids has been done with varying degrees of success over the years. In this author's experience, nitrogen seems to work best at higher pressure gradient levels and that lower pressure gradient levels tend to interfinger back through the fluid causing loading conditions. Additionally, wellhead pressure using nitrogen will significantly increase due to the lower average density of the total system. This, of course, increases the required hydraulic horsepower and potentially, the required working pressure of the surface equipment.

With the increasing availability of carbon dioxide for oil field use, we have been able to successfully unload two wells with extremely low pressure gradients. One of these wells is slightly below 5000′. The other was slightly below 22,000′. The jobs were designed similarly with the obvious difference in scaling factors. We chose carbon dioxide due to the density and the similarity of the gas in its compressed state to a liquid. We designed the jobs so that at no time would there be enough total fluid volume in the tubing to reach loading conditions. Additionally, we preceeded and followed the acid jobs with a full tubing volume of carbon dioxide.
Two Years of Successful Turbodrilling in the Anadarko Basin
Authors: Viricel Roger
Published: December 2007

The use of straight hole turbodrills associated with diamond bits in the Anadarko Basin is discussed with reference to the optimization of drilling performance and to the techniques employed within the restraints of the local operating parameters. Examples are provided which demonstrate the ability to adapt performance proven turbodrills to the local conditions to improve drilling performance and maximize rates of penetration while concurrently avoiding costly deviation and down hole problems.
Batch Treatments of Deep Gas Wells Using Water-Soluble Corrosion Inhibitors
Authors: Houk James L , Bufkin Larry B.
Published: December 2007

Batch treatments of deep gas wells are common methods of corrosion control in West Texas. The majority of the batch-treated wells are treated with an oil-soluble, water-dispersible corrosion inhibitor mixed with a hydrocarbon solvent. Many wells are batch treated with water-soluble corrosion inhibitors, and this can be an effective method of treatment.
Cased Hole Exploration and Recompletions in West Texas Based on the Continuous Carbon/Oxygen (C/O) Log
Authors: Flynn J. , Conley S. , Frost E. , Fertl W. H.
Published: December 2007

Recent field experiences in West Texas with the Continuous Carbon/Oxygen (C/O) Log illustrate the potential of this cased hole logging service to assist in the re-evaluation of partially depleted oil reserves and exploration for by-passed oil in old wells in mature, producing areas.

Interpretive concepts and possible pitfalls are outlined for quick-look evaluation at the wellsite and detailed computerized analysis. Field case examples, including the results of subsequent production tests in the Yates, Seven Rivers, Queen, Grayburg, San Andres, Glorieta, and Clearfork formations illustrate successful applications of the C/O Log in West Texas.
Thermal Techniques for the Recovery of Heavy Oil and Bitumen
Authors: Nasr T. N. , Ayodele O. R.
Published: December 2007

Over 90% of the world's heavy oil and bitumen (oil sands) are deposited in Canada and Venezuela. Alberta holds the world's largest reserves of bitumen and the reserves are of the same order of magnitude as reserves of conventional oil in Saudi Arabia. Up to 80% of estimated reserves could be recovered by in-situ thermal operation. As the resources available for conventional crude in Canada continue to decline, further development of heavy oil and oil sands in-situ recovery technologies is critical to meeting Canada's present and future energy requirements.

Sophisticated technologies have been required to economically develop Canada's complex and varying oil fields. Various existing in-situ technologies such as hot water injection, steam flooding, cyclic steaming and combustion processes have been successfully applied in Venezuela and California. Most recently, advances made in directional drilling and measuring while drilling (MWD) technologies have facilitated development of new in-situ production technologies such as the steam assisted gravity drainage (SAGD), expanding solvent-SAGD (ES-SAGD) and solvent vapor extraction (VAPEX) that have significantly improved well-bore reservoir contact, sweep efficiencies, produced oil rates and reduced production costs.

This paper provides an overview of existing and new thermal in-situ technologies and current projects. Potential of new technologies are assessed and compared to various existing in-situ thermal processes. Critical issues affecting production performance are discussed.
Prediction of Hydrogen Sulfide and Carbon Dioxide in HPHT Wells
Authors: Grimes William D. , McNeil Robert I.
Published: December 2007

It is can be readily demonstrated that hydrogen sulfide (H2S) and carbon dioxide (CO2) partial pressure can be estimated based upon formation temperature for hot (>275ºF), high pressure, high temperature (HPHT) clastic reservoirs. This knowledge is extremely useful in the practice of sour service materials selection and materials qualification.

In fact for H2S, for early, untested wells in a field development program, it is recommended that these geochemical projections be used even if downhole sample analysis results are less than the projection. Even minor errors in H2S parts per million (ppm) due to filtrate, sample process, or analytical scavenging may lead to significant errors in equipment materials selection. The sensitivity to these H2S sampling errors is especially critical in the temperature range of 300-380ºF.

Likewise, CO2 can also be estimated, and the results of these two correlations can be used for pH prediction of downhole conditions. The resultant projected gas acidity and pH is then useful in ISO 15156/NACE MR01751 materials qualification work and corrosion control planning
Wireline Evaluation Technology in HPHT Wells
Authors: Sarian Serko , Gibson Arthur
Published: December 2007

Traditionally Wireline logging tools are rated for continuous operation to 350°F and 20,000 psi downhole conditions. With many reservoirs exceeding these limits, the need for specialized, High-Pressure and/or High-Temperature Wireline tools has been an issue for some time. Sensors were accordingly developed to ratings of 500°F and 25,000 psi. Recently, Ultra-Deep drilling has pushed the boundary to above 25,000 psi, resulting in the development of 30,000 psi and 500°F rated wireline tools. Currently, basic Petrophysical evaluation Quad-combo strings are available and wells in excess of 480°F, 26,000 psi have been successfully evaluated. Significant work is underway to upgrade specialized wireline services such as pressure testing, fluid sampling, dipmeter imaging, sidewall coring, Dipole Sonic, Magnetic resonance, natural and spectral Gamma ray measurements.

Like most other oilfield services, Wireline HPHT technology development pauses serious challenges. When the extreme is temperature or pressure only, the solution is relatively simple. Significant complications arise when both extreme conditions occur simultaneously, requiring at times timely and costly redesign of sensors and related electronics. The paper follows Wireline HPHT evaluation development to date, outlines technological challenges and barriers to continuously expand current tool rating limits while increasing the range of services. Recent case histories from North America are presented. Finally future development and well evaluation technology trends are discussed.
The Role of Idealization Uncertainty in Understanding Design Margins
Authors: Klever Frans J. , Tallin Andrew G.
Published: December 2007

Limit states design is based on explicitly modeling the likely failure modes. Design margins ensure safety and durability by accounting for uncertainties in loads, strength, environmental exposure and idealization. This paper examines the idealization or model uncertainties. These uncertainties are particularly important when extending the limits of conventional design, such as HPHT well design.

The purpose of the paper is to discuss how such uncertainties could be handled for fracture mechanics based limit states. The paper provides a basic overview of commonly used FAD methods and some of its limitations. A survey of published verification tests was made to see whether this data could be used to estimate FAD idealization uncertainty.

The authors conclude that available data is not directly applicable to well design. A testing program is recommended to establish the model uncertainty for sour fracture of casing.
A Case History of Sustainable Annulus Pressure in Sour Wells – Prevention, Evaluation and Remediation
Authors: Milanovic D. , Smith L.
Published: December 2007

This paper describes evaluation of the possible causes of Sustainable Annular Pressure (SAP) in a sour gas field in the Middle East. It explains the diagnostic testing undertaken and describes how evidence was used to identify the cause of the SAP. The steps taken to prevent the occurrence of SAP in new wells and to remedy the problem in existing wells are described.

This practical approach, based on critical assessment of many aspects of the whole well condition put the SAP problem under total control, covering the process from well design through the lifecycle of the well. This all-encompassing approach is regarded to be essential for all sour gas wells, but especially for HPHT designs.
The Submersible Pump: It Can Be Compatible with Surface Equipment
Authors: Durham Marcus O. , Boyer Lynn
Published: December 2007

A method of selecting submersible pump equipment is outlined which emphasizes economics, conservation, and compatibility. Reduction of inventory expense is demonstrated by elimination of specialized components. The system is designed to minimize waste energy due to power drop in submersible cable. Interchangeability between submersible and surface installations is obtained by prudent selection of transformers and controllers. An installation containing 40 submersible pumps is used for evaluation of past practices and our systems approach. An economic comparison is made with this data.
Numerical Studies of Oil Production from Initially Oil-Wet Fracture Blocks by Surfactant Brine Imbibition
Authors: Adibhatla B. , Sun X. , Mohanty K. K.
Published: December 2007

Little oil can be produced from fractured oil-wet reservoirs by water flooding. Introduction of surfactant into the brine phase can improve the oil production by lowering the oil-water interfacial tension (IFT) and by altering the wettability of the matrix block to water-wet. A 3-D numerical simulator is developed to model this process. The capillary pressure, relative permeability and residual saturations of both phases are considered as functions of IFT and wettability, which are correlated to the surfactant and salt concentrations based on the data obtained from laboratory experiments. The mass balance equations are solved with a fully implicit scheme. Numerical simulation matches the experimental data obtained for alkaline surfactant imbibition. Simulation results indicate that both capillarity and gravity help to improve oil production: in the early stage of the production, capillarity is found to be the major driving force, and in the later stage, gravity dominates the production. Surfactant diffusion into the matrix block leads to IFT and wettability alterations which in turn lead to oil mobilization. Oil recovery by the time surfactant completely diffuses into the matrix block is found to be about 30% of the total recovery. As matrix block height increases, or surfactant alters wettability to a lesser degree, or permeability decreases, oil production rate decreases.
Three-Dimensional, Randomized, Network Model For Two-Phase Flow Through Porous Media
Authors: Lin Cheng-Yuan , Slattery John C.
Published: December 2007

A structural model for a porous medium in the form of a randomized, three-dimensional network is developed that can be used to calculate permeability, capillary pressure as measured under static conditions and during steady-state flows, and relative permeabilities as measured during steady-state flows.

This randomized network model, expressed in terms of seven free parameters, can be employed to correlate for a given system the single-phase permeability, the drainage and imbibition capillary pressure curves, and the two drainage relative permeability curves. The subsequent portions of the hysteresis loops for capillary pressure and for the relative permeabilities then can be predicted.

The limited data available from the literature for unconsolidated packed beds have been successfully correlated: 100 to 200 mesh sand and uniform 181 μm glass spheres. Data for a bed of sintered 200 μm glass beads also has been successfully described.
The Next Step: Personal Responsibility for Safety
Authors: Bowyer M. , Sawaryn S. J. , Smith N.
Published: December 2007

Improvements in technology and systems have greatly reduced injury rates in the oil and gas industry. To seek further reduction, in the mid 90's, focus shifted to behaviors and culture. In the UK continental shelf, the Step Change in Safety (SCIS) initiative has played a major role in improving safety since its formation in 1997. Improvements have been achieved by fostering collaboration between its 128 members, including employees, service companies, operators, trade unions, regulators and representative bodies. It is recognised that good practice can be found in most aspects of safety in this large and diverse membership. The challenge is to bring these together in a harmonised approach.

In 2003, SCIS launched a "Personal Responsibility for Safety" (PRfS) programme to prepare and deliver common guidance to assist the acceptance of Personal Responsibility for Safety. This guidance highlights good practice that will assist in driving further improvements in safety performance. A workgroup categorised safety behaviors in 9 elements. A simple questionnaire was then used to target more detailed interviews and acquire source material from more than 30 companies. The material covers: setting expectations, communication, leadership, risk awareness, planning, intervention, accountability, self evaluation and sustaining safe behaviors. The PRfS guidance document has been published, the next step towards the goal of making the UK the safest place to work in the world-wide oil and gas industry.

This paper contains a detailed discussion of the development of PRfS in the UKCS, and the later rollout and response. Brief details of the project's organisation and execution have been included for those interested in organising a collaborative effort on this scale. The paper will be of interest to individuals, supervisors and managers wishing to understand, establish, or improve a culture of personal safety in their organisation.
Phase Behavior Effects on the Oil Displacement Mechanisms of Broad Equivalent Weight Surfactant Systems
Authors: Gash Bruce W. , Griffith David T. , Chan Albert F.
Published: December 2007

Multi-component micellar fluids containing broad equivalent weight surfactants, such as vacuum gas oil (VGO) and polybutene sulfonates, are being considered for commercial applications of micellar flooding. These surfactants are attractive for such applications because they are considerably less expensive than the more pure sulfonates.

A phase behavior study of micellar fluids containing VGO sulfonate as a function of salinity, hardness, brine dilution, temperature, cosurfactant type, and surfactant-cosurfactant ratio was used to define the region within which stable micellar fluids can be formulated. The phase behavior study demonstrates that for micellar formulations within the stable region that contain 10 wt. % surfactant, the addition of an equal volume of oil (decane) normally produces Type I microemulsions (Winsor's notation). More dilute micellar fluids (1 wt. % surfactant) show Type III behavior. Effluent analyses from corefloods show that VGO sulfonate remains almost exclusively in the water phase (although a small amount of Type III microemulsion was observed in some of the effluent). This suggests that the recovery mechanism for the VGO sulfonates is dominated by the Type I lobe of a Type III phase environment.

Phase behavior tests of polybutene sulfonates show that in the presence of calcium the sulfonate partitions into the oil phase forming microemulsions in a Type II lobe of a Type III phase environment. During displacement tests in the presence of calcium, polybutene sulfonates partition into the oil phase generating such microemulsions in situ.

The use of a Type II to Type I phase transition in moving partitioned sulfonates was investigated. Type II microemulsions generated external to the core were injected to displace the in-place oil. These were followed by a fluid designed to produce a phase transition from Type II to Type I. The Type II microemulsion miscibly displaced the inplace oil. The phase transition microemulsion flood displaced oil more efficiently at higher salinity and hardness levels than has been obtained using conventional micellar fluid formulations of VGO and polybutene sulfonates.
SDLA: Fighting Skin Damage in Colombian Fields—A War Story
Authors: Franco C. A. , Restrepo A. , Acosta L. G. , Junca E.
Published: December 2007

The well damage history in the fields operated by BP Colombia has showed an interesting performance in all producer and injector wells. The abnormal productivity decline detected since the start-up in 1991 was a clear evidence of the skin damage magnitude, in fact, the fields have not plateau history. The initial high oil and gas rates production added to strong geological structures in which a variety of fluids have been producing (critical volatile and gas condensate) have contributed to the development of a very complex damage scenario; main damage factors identified at early stage of production were fines migration and mineral scales (calcite, siderite, barite, celestite and iron compounds). Research regarding acid stimulation and mineral scale inhibition was the first step trying to mitigate the high oil rate decline. New damage mechanisms were detected as long as the fields were in production, water and condensate blockage, organic scales (wax and asphaltenes), iron sulfide scales, and wettablity changes were the main damage mechanisms detected. Engineering work, laboratory and geological studies, backflow analysis, third parties investigation and an extensive field trial program have been developed to determine the best stimulation program that should be applied in each one of producer/injector wells. Although high success removing formation damage has been obtained, it has been necessary to focus additional effort to find and test new technology addressed to increase both IIOR and stimulation lifetime.