bluuebunny/crossref_metadata_2025 huggingface dataset:
Champion East, Low Cost Redevelopment of Shallow, Stacked and Faulted Heavy Oil Reservoirs
Authors: van Kessel Onno
Published: December 2007

The Champion East area offshore Brunei Darussalam consists of around 50 stacked, intensely faulted heavy oil reservoirs, spanning a depth of 200–1200 m ss. These reservoirs have been under development since 1975 and have to date produced just 8% of the oil initially in place. Over the period 1998–2003 Brunei Shell Petroleum (BSP) is embarking on a major redevelopment, with the aim of converting a further 30 million m3 of oil-in-place volume into commercial reserves—requiring at least a 50% reduction in unit development cost against the background of the prevailing, economically tough business environment.

An overview will be given of how new technology is adding value to the total redevelopment, supported by actual application results and learning points. At the same time, Shell’s process of converting notional ‘scope-for-recovery’ volumes into bottom-line reserves additions through forward planning of requirements for technology, studies, IT tools and data, will be highlighted.

The primary development of Champion East is now nearing completion, with a 30-well infill drilling campaign almost finished. This campaign uses existing facilities and ultra-shallow long-reach horizontal wells—with innovative sand exclusion and downhole ‘intelligence’—and has achieved a 60% unit cost reduction over previous drilling campaigns in the area.

The only way to unlock another 5–15% of the oil-in-place volume is to start secondary recovery through water injection, in combination with the use of Electric Submersible Pumps. Long term business value will be secured in two ways: (1) by implementing a limited pilot water injection scheme, using mostly existing wells and facilities, in 2001—again aiming for a 60% unit cost reduction over previously proposed schemes; (2) by data acquisition, studies and sponsoring of joint research programmes (in-house and 3rd party) covering 4-component OBC seismic, chemical and mechanical water shut-off techniques, geochemistry, special core analysis, development of slimhole high-GOR ESPs, produced water reinjection and geomechanics.
Field Experiment of Enhancing Heavy Oil Recovery by Cyclic Fuel Gas Injection
Authors: Zhang Fengshan , Fan Xueping , Ding Jianmin
Published: December 2007

Of the oil produced by Jinzhou Oil Company, Liaohe Petroleum Corporation, 72.7 percent is heavy oil, mainly recovered by cyclic steam injection method. As for the major pay zone, Block Jin-45 and Block Jin-7, the average number of huff-and-puff cycles is as high as 8.9, and average fluid pressure is dropped to 4 MPa at the depth of 1000 meters. Non-uniform production worsens the situation: Oil/steam factor is dropped to 0.49; Natural reduction rate is as high as 46%; and the profit is decreasing year by year. To maintain a sustainable and steady increase in oil production under the current situation, experiments of combined fuel gas and steam cyclic injection were first carried out on heavy oil wells, taking into account the current situation of our oilfield and the development history of similar oil fields in and outside China. After nearly one year’s field experiment, identifiable results have been discovered, such as less air pollution resulted from the emitted gas, better protection of the casing, fewer heat-insulation pipes, more modification of steam injection profile, higher production rate, shorter water drainage period, and greater reduction of operation cost. By the end of year 1999, 599448 cubic meters of fuel gas has been injected into six wells in Block Jin-7 and Block Jin-45; 3350 cubic meters of steam was saved and 1964 tons of incremental oil was obtained. The social and economical efficiency was obvious.
The Potential of Carbon Dioxide Gas Injection Application in Improving Oil Recovery
Authors: Abdassah D. , Siregar S. , Kristanto D.
Published: December 2007

Carbon dioxide (CO2) gas could increase oil recovery by means of swelling, evaporating and lowering oil viscosity. In the displacement front, injected gas may become enriched by the oil components and gas may dissolve into the reservoir oil. By assuming that local thermodynamic equilibrium is occurring at the oil-gas interface, the phase behavior can be calculated by the equation of state.

The displacement process can be modeled by a set of differential equations, called the mass balance equations, which can be written for each component in the reservoir oil and the CO2 gas injected. The linear velocity component in the mass balance equation is expressed by Darcy’s law for oil and gas phase flow, which comprise oil and gas permeability, oil and gas viscosity and pressure gradient terms. A set of the flow equation then solved numerically by the use of a one dimensional compositional simulator. The simulator has been validated by analytical methods, which is based on the method of characteristics.

In this study, we want to see the potential of CO2 injection application in improving oil recovery by simulating a slim tube experiments. CO2 gas is available in large quantity in the Natuna Sea and some place in Kalimantan, Indonesia. The benefit of the study is that we could predict the recovery efficiency of CO2 gas injection in the field by combining the results here with the macroscopic areal sweep and invasion efficiencies obtained from other models or simulations. And, the potential application of the study is that we could have a good estimate of the recovery improvement under CO2 gas injection, which will be the basic input parameters for the economic feasibility study and also a decision can then be made whether to implement or abandon the prospective project.
Research on Packing Materials for Sand Control in Steam Injection Wells
Authors: Chen Duanzong , Jin Qianhuan , Xu Riyi
Published: December 2007

Recovery of highly viscous oil requires thermal recovery method with steam injection into the formation. Severe sanding problem is one of the major contradictions in oil production for this type of reservoirs because of unconsolidated formations.

Traditional sand-control technology used in steaming wells is gravel pack with wire-wrapped screen. Many foreign scholars think that the packed gravel (quartz sand) will be greatly dissolved by high-temperature steam injected, so that gravel cannot be applied to sand control in steaming wells. Thereby, many efforts have been done to search for some new packing materials with lower dissolubility and high-temperature resistance in wet, saturated steam to replace the traditional gravel. However, these new materials are not commercially used because of expensive cost.

This paper describes the systematic lab research on quartz sand behavior in detail. Lab tests and field application have proved that gravel (quartz sand) is still an effective packing material for sand control in steam injection wells. It is not necessary to worry about the dissolving corrosion of gravel leading to sand-control failures, and not necessary either to employ some special materials for packing with much higher cost.

This research fruit has been successfully used in various fields in China with attractive sand-control and production results.

Field practice shows that many gravel-packed wells have been produced successfully under the condition of high-temperature steam injection (320°C–350°C) for more than 6 cycles of huff-and-puff.
An Accurate Characterization of Sand Strength in Weak and Unconsolidated Formations Aids Offshore Production Test Designs - A Bohai Bay Case Study
Authors: Ong Seehong , May Andy , George Ian , Walker Tim , Zheng Ziqiong
Published: December 2007

This paper presents a case study where the creative use of wireline-derived sand strength in the offshore production test process improved operational efficiency. Sand strength was computed using wireline data only and subsequent testing of two wells verified the accuracy of the calculations.

Well logs provided the basis for evaluation of formation petrophysical and mechanical properties. These log-based properties enabled a foot-by-foot profile of the critical drawdown pressure to be generated. Analysis of critical drawdown pressures in the Bohai Wells A and B, located in the northeastern People’s Republic of China, provided a cost-effective method to predict potential sand production problems. This information proved invaluable in reducing the risk and costs associated with the testing of viscous oils in the shallow, moderately unconsolidated sandstones of Bohai Bay.
Improving the Static Model of a Complex Reservoir through the Inversion of Seismic Data
Authors: Marzuki Zakaria B. , Sams Mark S. , Atkins Dave
Published: December 2007

It is common practice to build static models of reservoirs based on simple algebraic combinations of well log data within a structural framework. This can potentially lead to large errors in estimating volumetrics due to oversimplification of the reservoir geometry, underestimation of the reservoir heterogeneity and the miscorrelation of flow units between the wells. In addition a biased estimate of uncertainty is produced that can distort the quantitative assessment of the risks involved in field development.

Seismic data can be used at various levels of sophistication to guide the interpolation of log data between the wells to provide more realistic static models. The most effective way to include the seismic data is through the construction of impedance models derived from seismic inversion and geological modelling. This ensures that the well log and seismic data are tightly integrated within a geological model. Geostatistical techniques can be applied to generate models of reservoir properties such as porosity that honour not only the detail provided by the well data but also the complexity and heterogeneity of the reservoir between the wells as defined in the impedance model. These techniques also produce an estimate of the uncertainty associated with this interpolation.

A number of static models that include the seismic data and those based on log data alone have been compared for an oil field from the Malay basin. Significant differences in volumetric estimates were found. These differences were caused by the variations in sand quality across the field that were misrepresented when the seismic data were not used.
The Use of Four-Component Seismic for Improved Reservoir Imaging and Reservoir Characterization
Authors: Fromyr Eivind , Randazzo Santi , Lynn Walt
Published: December 2007

In recent years, the development of marine four-component (4-C) acquisition and processing technology has made it possible to apply the technique in most geographical areas and in a wide range of water depths. Due to higher cost compared to conventional streamer surveys, a key to future success of 4-C technology is to identify proper geophysical uses and demonstrate that results can be interpreted and used in ways that make the technology cost efficient. In this paper, we will discuss the 4-C data results associated with three different case histories, each showing a different application of the technology. The applications cover both reservoir imaging and reservoir characterization.
Recovery Area and Reserves Increment by Tapping the Potential of Regions Beyond the Oil-Water Transition Zone
Authors: Yulin Ren , Ying Lin , Chengdou Ma , Qingxia Wang
Published: December 2007

Through analysis on transitional zone and extending pilot area in Daqing oil field, oil and water distribution regularity, formation development status of transitional zone and extending area are studied in this paper, clarifying the extending potential of the pilot area. The problem of crude oil out flow during development in transitional zone is comprehensively studied, rational water injection pressure limit in transitional zone is provided by combining numerical simulation, the extending development principle of transitional zone is concluded, all these would provide theoretical basis and practical experience for guiding the extending and potential tapping of transitional zone.
Non-Equilibrium Adsorption and Precipitation of Scale Inhibitors: Corefloods and Mathematical Modelling
Authors: Zhang H. , Mackay E. J. , Chen P. , Sorbie K. S.
Published: December 2007

Adsorption/desorption and precipitation/dissolution are thought to be the two major mechanisms operating in the retention and release of scale inhibitor in squeeze treatments in an oil reservoir. The general nature and extent of the scale inhibitor adsorption process is determined principally by the equilibrium isotherm, although the shape of the inhibitor return curve may be significantly modified by kinetic effects for a specific squeeze practice. For a precipitation squeeze process, the solubility of the inhibitor-calcium complex and the rate of dissolution are currently thought to be two main factors that govern the return curves in our computer modelling studies. Experimental coreflood techniques can be used to provide inhibitor breakthrough profiles and these effluent concentration data can then be used to derive isotherms for the adsorption systems or to test the validity of the above precipitation mechanisms.

This paper presents results from a series of flow rate varying adsorption and precipitation laboratory corefloods for a penta-phosphonate (DETPMP) and a poly-carboxylate (PPCA). This experimental data is the most complete and accurate ever produced and is of a quality that allows us to test the details of the above mechanisms. A general analysis and discussion of the adsorption isotherm derivation is provided and modelling results for the non-equilibrium adsorption corefloods are reported. The significance of these results for field applications is discussed.
Productivity of Selectively Perforated Vertical Wells
Authors: Yildiz Turhan
Published: December 2007

This study presents analytical models to predict the productivity of selectively perforated vertical wells. The models consider arbitrary phasing angle, non-uniform perforation size and length, and formation damage around perforations. The accuracy of the models were verified against the results from electrolytic models and the semi-analytical correlation proposed by Karakas and Tariq.
A Modified Genetic Algorithm for Reservoir Characterisation
Authors: Romero C. E. , Carter J. N. , Gringarten A. C. , Zimmerman R. W.
Published: December 2007

This paper describes the implementation of a Genetic Algorithm (GA) to carry out hydrocarbon reservoir characterisation by conditioning the reservoir simulation model to production data (history matching) on a predefined geological and structural model. The proposed technique combines the advantages of the pilot point method for the description of petrophysical properties, with the advantages of GAs for global optimisation.

The modified GA uses a complex genome, which is divided into seven separate chromosomes for different types of reservoir parameters. Chromosomes containing the pilot point information are three-dimensional real number structures which include information for the wells, while the chromosomes for all other parameters are one-dimensional arrays. Specially designed crossover and mutation operators have been created to work with the non-standard genome structure. Results from tests on several GA design issues are presented, including crossover and mutation operators, encoding, selection, and other population strategies such as elitism. In addition, a comparison is made with a standard Simulated Annealing algorithm.
Quantification of Uncertainties on Volumes in Place Using Geostatistical Approaches
Authors: Doligez Brigitte , Chen Liang
Published: December 2007

At the exploration and development phase of an oilfield, there is limited amount of hard data for reservoir characterization. For that reason significant uncertainty exists in the life of the oilfield. Especially uncertainties on volumes in place (VIP) are important, contributing to decisions being made with respect to facilitate design and commercial evaluation. Therefore the issue of uncertainty management and quantification has been recognized as crucial by petroleum industry.

The calculation of VIP involves several parameters and a number of nonparametric factors. VIP uncertainties come from many sources, however major uncertainties exist on geological parameters. Geological complexity can make reserve estimation uncertain. Geostatistical approaches can help in understanding the magnitude of this uncertainty.

A framework for quantifying VIP uncertainties is presented in this study. Our method is to divide the potential uncertainties into structural, sedimentary facies, petrophysical properties, and to use multiple stochastic reservoir models in a systematic way to evaluate the impact of each of those on VIP forecasts. Moreover, we perform tests of sensitivity using different geostatistical methods, different initial constraints, different initial data to hierarchies the influence of the uncertainties on the data depending on the chosen simulation method. Also an overall quantification of uncertainties is illustrated clearly from a nonmarine reservoir.
Gas Loss Determination from a Well Blowout - A Simulation Approach
Authors: Horton Lary D. , Kobelan Mark T. , Singh Surendra P.
Published: December 2007

A simulation approach was used to determine the gas loss from a storage field after a well got out of control during a replugging attempt. Because the event occurred in a storage field which has over 250 active wells, a smaller portion of the reservoir surrounding the problem portion of the reservoir surrounding the problem well was selected for reservoir simulation. The movement of gas into the smaller portion of the reservoir from the rest of the reservoir was simulated by using pseudo injection wells in the model.

The pseudo wells were placed at the grid boundary where gas migration was expected to occur. Wells surrounding the incident well were shut-in for pressure observation throughout the event and were included as observation wells in the model. By assuming different injection rates in the pseudo wells with various assumed loss rates from the incident well, a good history match was obtained. From these studies, an accurate estimate was made of the natural gas lost during the 16 day incident.

Introduction

The Taggart Storage Field (originally called the Six Lakes Field) was discovered on May 11, 1934 at a wellhead discovery pressure of 513 psig. The field was developed on 40 acre spacing. By March 1, 1936 there were 75 gas wells and ultimately there were 224 producing gas wells. The largest gas well had an initial gas flow potential of 112,000 MCF per day.

The reservoir is the "Stray Sandstone" unit in the Michigan Formation of late Mississippian Age. The reservoir is a structural trap (Fig. 1) in a porous and permeable sandstone that can be correlated for many miles across Michigan. Porosity of the sandstone ranges from 15–23% and Porosity of the sandstone ranges from 15–23% and permeabilities are as high as 1000 millidarcies. permeabilities are as high as 1000 millidarcies. The reservoir is approximately 1300 feet deep and has a maximum gross thickness of 50 feet (Fig. 2).

By March 12, 1953, the Taggart Field had produced 51.3 BCF and was essentially depleted. produced 51.3 BCF and was essentially depleted. All but 64 of the original 224 gas wells had been plugged and abandoned, due to water encroachment. plugged and abandoned, due to water encroachment. Michigan Consolidated Gas Company had completed acquisition of mineral interests and storage rights at that date. The company then started to develop the field for underground gas storage. It was necessary to reopen all of the plugged and abandoned gas wells and to convert them to facility wells with new casing or replug them to prevent leakage. prevent leakage. Many of the old wells had both the surface and production casing shot off or ripped when they were abandoned. This made it difficult to locate them. As of 1974 there remained thirty five wells to be replugged. Twelve of these wells had been relocated with a Casing Finder Tool. One of these 12 wells, the S. L. #375, was plugged in 1949.
The Hydrogeologic Cycle And Its Relationship To Geologic Processes
Authors: Parizek Richard R.
Published: December 2007

The concept of the hydrologic cycle, the germ of which was conceived of by Plato and expanded upon by Vitruvius, Palisay, Perrault, Mariotte, Halley, Lametherie and others required more than 2000 years for its acceptance. The physical and chemical factors that govern the state, occurrence, movement, quality and quantity of water in various segments of this cycle are still being clarified 2300 years after Plato advanced his pluvial concept in "Critis's." Man's understanding of the natural laws that operate in the hydrologic cycle and his engineering mastery over them holds the key to his successful evaluation, development, and management of water in all segments of this cycle.

Water in the hydrologic cycle serves as an active and passive agent to geologic and other processes and has played a varied and significant role in shaping geologic events. Since water is an intimate agent to geologic processes, it should not be thought of exclusively in the restricted sense of man's economic exploitation of water, his social and aesthetic benefits nor the harassment it causes him due to its overabundance or scarcity.

Consideration of the role of water in the hydrologic cycle through geologic time and of water not generally considered part of the hydrologic cycle requires that recognition be given to a second grander cycle - the hydrogeologic cycle — which involves the interaction of earth materials and water under varied environmental conditions from sediment accumulation to tectonics.
Corrosion Inhibition Of Gas Pipelines By Chemical Treatment
Authors: Robertson A.R. , Stanford J.R. , Chappell G.D.
Published: December 2007

Gas shortages, inflated pipeline replacement costs, and gas losses caused by internal corrosion have caused gas gathering and storage companies to become very concerned about internal corrosion in pipelines. Gathering systems take gas of pipelines. Gathering systems take gas of lower quality now more than ever before. Storage systems are pulled harder and longer, thus, more corrosive liquids are produced on withdrawal. The need exists for a specialized internal corrosion control program for gas handling systems. A program has been developed that includes detection of internal corrosion, treatment and monitoring of treatment results.

The energy shortage of recent months has helped focus attention to the internal corrosion problems in gas pipeline systems. However, internal corrosion and treatment in gas gathering systems has been documented since the early 1950's. This early treating program was accomplished by using an oil soluble water dispersible corrosion inhibitor. Application was by slug treatment and later as an inhibitor mist. Although the inhibitor program was successful in controlling corrosion, side effects such as sludge and emulsions occurred.

Internal corrosion in gathering systems is caused by acid gases in water and usually occurs along the bottom and sides of the line. In low flow systems where gas production has declined, corrosion and failures production has declined, corrosion and failures can take place on the upper surfaces of the pipeline. pipeline. In gas storage systems, the traditional treatment is with biocide and/or corrosion inhibitor. The chemical is mixed with water or a suitable solvent, pumped into the storage well and followed with gas. This method assumes the gas will displace the chemical mixture into the formation to control bacterial growth. Although negative bacteria cultures have been noted with this type of treatment there is concern that the biocide stayed in the bottom of the well or near the well bore and was not carried far into the formation where bacterial growth still continues.

Side effects of biocide treatments are foaming, emulsions, and expensive equipment costs for individual well treatments.
Experimental Study of Fluid/Rock interaction Caused by Drilling and Cementing Filtrates in Carito Field
Authors: Gambino F. E. , Guimerans R. , Galarraga F. A. , Pestana D. C. , Rojas E.
Published: December 2007

Fluid–Rock interactions were evaluated using formation rocks and fluids from Carito Field at East of Venezuela, in order to establish better criteria for the design of more efficient cement spacers. Rock and formation fluids were analyzed before and after exposure to overbalanced drilling and cementing filtrates through formation cores. Rock changes were evaluated by X-ray diffraction, SEM, permeability and wettability, whereas fluids were analyzed by fluid and gas chromatography, GC - MS, NMR and IR. Results indicate that 100% oil based mud filtrate produces a large permeability reduction. Spacer A showed greater mud removal efficiency than spacer B, whereas the cement slurry filtrate generates lighter formation permeability reduction than the oil-based mud, after either spacer exposure. This can be explained due to insoluble salts' precipitation when the cement filtrate is in contact to the residual formation water.

The molecular analysis of crude samples indicates that the absence of heavy molecules from hopane compounds in the crude saturated fraction could be related to adsorption of these compounds on the rock surface, which is partially oil wettable. In addition, absence of C15 – C20 molecules from crude oil is related to molecular distribution in the gasoil from mud and spacers evaluated. The results of these tests indicate interaction between crude oil and rock composition with drilling and cementing filtrates. Overall results of this study will allow achieving a more efficient approach for design of spacer fluids.
The Development of a Novel Environmentally Friendly Dual Function Corrosion and Scale Inhibitor
Authors: Collins I. R. , Hedges B. , Harris L. M. , Fan J. C. , Fan L. D. G.
Published: December 2007

Production chemicals being discharged into the natural environment are increasingly becoming scrutinized for their impact on the environment. New and existing chemicals for scale and corrosion control are likely to be impacted by the developing legislation and regulatory control. Therefore, there exists an urgent need to bring the marketplace new chemistry that is able to reduce the environmental impact while still retaining its excellent efficiency. This paper describes the development of novel polymeric chemistry, which has a dual functionality acting as both a scale and corrosion inhibitor under oil field conditions. This chemistry can be readily biodegradable and has achieved the stringent standards required for its use in the North Sea. Laboratory studies demonstrate that this chemistry can inhibit both carbonate and sulfate based scales. Corrosion experiments with or without flow suggest that greater than 90% of inhibition in a carbon dioxide rich environment can be achieved. The calcium compatibility of this chemistry far exceeds the performance of most commercially available scale inhibitors. The impact on oil and water separation, and subsequent oil in water content, is minimal.
Synergism and Antagonism of Foaming Agents and Corrosion Inhibitors
Authors: Pakulski Marek , Martin Richard
Published: December 2007

Continous or batch treatment of low pressure wet gas wells with foaming agents is a common and cost-effective method to sustain production from such wells. The foam additives convert well liquids into water/gas foams lowering the bottomhole hydrostatic pressure and increasing brine unloading from the well, thus preventing well "drowning" resulting in lower or ceased gas production. However, foaming surfactants being good wetting agents may accelerate the casing corrosion process and work against corrosion inhibitors. This effect would be particularly severe in deep wells having high bottomhole temperatures.

Foaming properties and steel corrosion rates were tested on fluids formulated with anionic, cationic, non-ionic and amphoteric foamers combined with the main categories of corrosion inhibitors. In most cases, there was a negative effect of corrosion inhibitors on foams or even a complete chemical incompatibility for some combinations. Occasionally, addition of certain corrosion inhibitors improved a foam's persistence and quality. However, the effect of a few percent of condensate seems to be stronger than 300 ppm of corrosion inhibitors. Additives had the greatest effect on the performance of non-ionic and amphoteric surfactants.

The effect of foaming agents on steel corrosion is not uniform. In most cases a surfactant offers some corrosion protection at mild conditions. Most foaming agents accelerate corrosion rates at high temperatures. Few chemicals produced spectacular corrosion.

Mixtures of foaming agents and corrosion inhibitors usually are less corrosive than foaming agents applied without any corrosion protection. However, no single component corrosion inhibitor reduced the corrosivity of such mixtures to an acceptable level.

The results indicate that wells that are being treated with foaming agents should also be treated with an appropriate corrosion inhibitor. For any particular application a proper combination of foamer/corrosion inhibitor should be selected. More consideration should be given to the properties of the foamer/corrosion mixture, than to those of the individual components.
Comparison of First and Multiple Contact Carbon Dioxide Induced Asphaltene Precipitation
Authors: Parra-Ramirez M. , Peterson B. , Deo M. D.
Published: December 2007

Precipitation of solids, believed to be asphaltenes is common in most carbon dioxide floods. The oils in most carbon dioxide flood applications, however, are light crudes with low initial asphaltene content. Precipitation is common after carbon dioxide breakthrough in production equipment. It is believed that precipitation does not occur in the reservoir. The objective of this paper was to identify the reasons for this phenomenon. The mature carbon dioxide flood at Rangely field in Colorado was selected as an example.

A high-pressure, high-temperature pressure-volume-temperature apparatus in conjunction with a high-pressure core flooding system was used to study carbon dioxide induced precipitation from the Rangely crude oil. Rangely crude contains about 1% heptane insolubles. It was determined that first-contact precipitation, at different carbon dioxide concentrations was negligible. Core flooding experiments at field conditions revealed that precipitation did occur at the core exit. This essentially showed that the precipitation phenomenon in crudes that are likely CO2-flood candidates is due to the multiple contact process and the associated compositional changes. Multiple contact experiments conducted to prove this hypothesis showed that multiple contact precipitation amounts were 3-5 times the first-contact precipitation values. The compositional changes (in the original crude) to cause widespread precipitation were established.

The precipitates from the field and various laboratory experiments were analyzed using GC and SARA, which showed that field precipitates contained compounds other than original heptane insolubles and also exhibited some unique features.
The Repairing Technology of Driving Channel on Small Drifting-diameter's Casing Damage in Daqing Oilfield
Authors: Lan Zhongxiao , Xia Yumin , Zhang Chuanan
Published: December 2007

Less than "70mm drifting diameter casing damage wells couldn"t be repaired by using normal methods. Its repairing is one of main tasks of oil and water wells workover and is a key to improve the workover rate. For this kind of wells, there is no effective repairing method in practice on domestic and abroad. The existence of the casing damage wells has seriously affected the results of exploitation, which restricted the oilfield continuing development. This paper introduced in detail on "139.7 mm casing and less than "70 mm the minimum drifting diameter"s casing damage by using two categories, mechanical type and explosive type, which can be diveided into five kinds of driving channels principles and methods. Its three kinds of matching cementing techniques i.e. explosive sealing welding, hydraulic sealing cementing, and mechanical slip sealing cementing are also introduced. After repairing, the inner drifting diameter of casing damage are ∮100 mm, seals loaded pressure 15 Mpa, hang capacity more than 400KN, the range of cemented length 1--100 m. After using this repairing techquies, it can adopt small diameter production casing of K344–95 to separately produce and inject water.
Conditioning Geostatistical Models to Flow Meter Logs
Authors: Mezghani M. , Lingen P. van , Cosentino L. , Sengul M.
Published: December 2007

This paper describes a method to condition facies (rock-type) permeabilities in geostatistical models to dynamic reservoir data: the flow meter log and the well test KH value. The proposed approach consists of two steps. In the first step, the flow meter logs are transformed into (reference) permeability profiles by use of the well test permeability–thickness (KH). This transformation is analytical, meaning that a geostatistical reservoir realization and numerical flow simulation are not required. In the second step, synthetic permeability profiles are computed for the known rock-type classification at the well locations. An optimization procedure is applied to improve the match of these synthetic permeability profiles with the reference (flow meter) profiles. In this process the initial (core based) rock-type permeability model is modified. The optimization procedure simultaneously takes into account all the wells, and is subject to geological constraints imposed by the user (ranking, permeability bounds). Although a number of assumptions must be verified, this fully analytical approach leads to a fast, flexible, and practical optimization routine that is relatively easy to implement. The up-front integration of dynamic data into the modeling process leads to a more representative permeability description than is obtained using only plug values. Because of the global nature of the optimization method, a satisfactory match can be extrapolated throughout the reservoir with a reasonable degree of confidence. The paper presents a successful application of the procedure to a Middle East reservoir.
A Comparison Of Sodium Orthosilicate And Sodium Hydroxide For Alkaline Waterflooding
Authors: Campbell Thomas C.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Alkaline waterflooding has been extensively investigated over the past 50 years in laboratory and field testing situations as a method for increasing crude oil recovery. Alkaline salts such as sodium silicate, sodium hydroxide and sodium carbonate have been cited in various patents and investigations as useful agents for patents and investigations as useful agents for improving water flood performance.

Laboratory measurements of interfacial tension (IFT) values between alkaline solutions of sodium orthosilicate and sodium hydroxide and several mid-continent and California crude oil samples have been obtained with a variety of types of injection water. In softened water with no Ca++ or Mg++ ions present, both alkaline salts exhibit similar reductions in interfacial tension with all the crude samples tested.

When unsoftened water was used to prepare alkaline injection solutions, sodium orthosilicate was effective in significantly reducing IFT values at concentrations of 0.5% to 1.0% with mid-continent crudes. However, using sodium hydroxide, even up to 5% by weight, IFT values with these same crudes were not reduced as much as with sodium orthosilicate.

Both alkaline salts were equally effective in reducing IFT values between the California crude oils tested and unsoftened injection solutions. The concentration of alkaline salt required to produce a minimum IFT value ranged from 0.01% to 0.5% by weight, depending upon the injection water used.

This paper will review the laboratory data which has been accumulated, and present a comparison between sodium orthosilicate and sodium hydroxide as alkaline waterflood additives.

Introduction

A recent article by Johnson provides an excellent review of the historical background, proposed mechanisms and the state-of-the-art proposed mechanisms and the state-of-the-art in caustic and emulsion methods for improved waterflood recovery of oil. The addition of alkaline chemicals to injection water has been proposed by many workers over the past six proposed by many workers over the past six decades (Reference 1 and the references contained therein). Considerable laboratory data and a few field trials have suggested that alkaline waterflooding, or modifications thereof, can provide an incremental increase in oil recovery under the proper operating conditions in selected reservoirs. At the present time there are several field trials of alkaline waterflooding under way or proposed.
On Real Time Reservoir Management and Simulation While Drilling
Authors: Bøe Ø. , Cox J. , Reiso E.
Published: December 2007

This paper addresses the problem of real time reservoir management and simulation while drilling. A software tool developed for this purpose is also described and discussed. Examples on use of the software are also presented.
Oseberg: Increased Recoverable Resources by Optimal Reservoir Management and Use of New Technology
Authors: Aasheim Ivar
Published: December 2007

The giant Oseberg Field is located offshore Norway 140 km Northwest of Bergen at approximately 100-m water depth. The field is developed with four offshore installations and the 1998 reserves estimate is 337 MSm3. Pressure maintenance is implemented by reinjection of associated gas and import of gas from the nearby Troll Field.

The field is by September 2000 producing approximately 42000 Sm3/d from 46 wells. Plateau production of 81000 Sm3/d ended in 1997. 82 percent of the expected reserves have been produced and the original oil leg of 215 m is now reduced to between 20 to 40 m in the main reservoirs. Gas treatment capacity is the bottleneck controlling the oil production rate and production is optimized on a daily basis based on individual well gas oil ratio.

The Oseberg field has been an offshore laboratory to implement new technologies as they have emerged during the late eighties and the nineties. The paper will discuss both successful and less successful technologies.

More than 80 percent of the production is currently coming from horizontal wells that have been drilled in the field since the early nineties. Typical horizontal well lengths are between 1200 m to 1700 m and are placed close to the water oil contact.

Geo-steering by use of navigator and autotrack has been applied for optimum well placement. Three multilateral wells with both branches exceeding 1200 m have been successfully established.

To increase the recovery and accelerate tail end production, intelligent completions in the horizontal wells are assumed to play an important role. Currently four wells with up to four independent zones have been completed.

Reservoir management on Oseberg has also involved WAG techniques and attempts with foam to shut of gas influxes. To monitor the gas flooding of the reservoir and well inflow profiles, wireline, coiled tubing and well tractors have been applied at a large scale.

Oseberg has been in the front-line to utilize geophysical technology and shot full field 3D seismic in 1982. The first 4D seismic was acquired in the central area of the field in 1989. In 1998 part of the field was covered with seabed seismic and a new conventional 3D seismic to map out remaining reserves was shot in 1999. Seismic attribute analyses have been used to map out channel sand deposits and dedicated production wells have been targeted successfully with this technique. Lately, seismic data have been visualized by "CAVE" technology for geo-steering purposes.
IOR/EOR – Over Six Decades of Romanian Experience
Authors: Paduraru Rodica , Pantazi Ion
Published: December 2007

The concern for new reserves discovery and the extension of the existing ones dates back to 150 years ago and since then oil production has become a tradition in Romania. Therefore, for over 6 decades, the IOR/EOR methods have been tested and applied at a commercial level in the already known reservoirs.

The paper presents the importance of using these methods (yielding about 12% of Romania's annual oil production), related to Romanian reserves structure (out of which about 32% are due to conventional methods and about 20% to unconventional ones).

The beginning was in 1925, when one horizon was drilled-in and produced by mining methods. In 1936, the first gas injection was recorded, while in 1950 began the first water injection process. Currently, water injection is applied on 181 reservoirs (about 1/3 of the reservoirs produced by National Romanian Oil Company).

The discovery of and the production from heavy oil reservoirs (where the conventional recovery methods application generally leads to modest results) showed the necessity of testing and applying new methods, namely thermal methods.

1964 is the year when the "Romanian tradition" began in the in-situ combustion application, on the Pannonian Suplacu de Barcåu reservoir, the best-known process of this kind worldwide. Due to its performances (production being maintained at the same level for over 25 years and a recovery factor of 56% in the area swept by the front), Suplacu de Barcåu remains the singular in situ combustion process in the country (other 5 processes being ceased recently due to economic reasons).

Other methods (chemical, microbiological, CO2 etc.) were also tested and extended to a commercial level.

For future increase of production process profitability, the increase of the oil produced per unit of injected agent, as well as the reduction of the produced water are aimed at.
Challenges Opportunities and Reservoir Management, of a Giant Field in Venezuela
Authors: Mengual R. D. , Rattia A. D.
Published: December 2007

The Naricual formation of the El Furrial field is a deep anticline oil reservoir. It was originally highly overpressure and the reservoir temperature was quite high. The medium-type crude oil has a large asphaltene content and the fluid properties change significantly with depth. The field is sealed off from the underlying aquifer by a 200 feet tar mat. The primary production mechanism is fluid and rock expansion.

A major data collection campaign for reservoir definition was set up right from the start of production. It resulted in a pressure maintenance programme whose objectives were the acceleration of oil production and the maximisation of the oil recovery and profitability.

The pressure maintenance project and the enhanced recovery methods that have been implemented were based on 400,000 barrel/day water injection, later to be increased to 550,000 barrel/day and 450 million standard cubic feet per day of miscible gas injection. Together with the primary recovery these projects were estimated to produce 3,210 million barrel oil, and increase the oil recovery by 33 % of the original oil in-place. An integrated reservoir management and a continuing actualisation of the reservoir model was required from the start. As an illustration, the geological model was refined eight times during the past 13 years and the ongoing exploitation plan was adjusted accordingly. Its implementation required flexibility of facilities and production operations.

This paper describes the field monitoring techniques of the water and gas injection. Tools and methods used to improve production and injection patterns have also been addressed. The application of resins, emulsions and diverting agents to control production and injection was excluded mainly due to the extreme reservoir conditions. Sand plugs have been set and intervals have been re-perforated with the aim of obtaining a more uniform injectivity and productivity. Their success ratio exceeded 70 %.

Finally, the paper provides information on current studies, whose short term implementation could lead to produce up to 55 % of the original oil in-place.
History Of The Formation Of An Oil Spill Contingency Organization
Authors: Barker Charles D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

APRIL:

Southern California - Petroleum Contingency Organization (SC-PCO) was formed as an unincorporated joint venture in April, 1976 by the Petroleum Co's. involved in the Federal Leasing program of the Outer Continental Shelf. Operating companies included (12) Arco, Texaco, Getty, Shell, Gulf, Marathon, Mobil, Challenger, Std. of Cal., Exxon and Champlin.

MAY:

Services of Chas. D. Barker were contracted for on May 17, 1976 as Gen. Mgr. Initial funding of $5,000/Operating Co. - $60,000 was deposited late May. Offices were acquired, furnished and moved into on June 1. Car leased, secretary hired and fully operational on June 7th.

JUNE:

Over 1/2 Million dollars worth of equipment on order by July 1st. Space acquired at Pier 200 - Wilmington for storage of equipment, (security, cranes and fork trucks on 24 hr. basis). Placed order for 050 Cyclonet. Placed order for 050 Cyclonet. JULY: Cash Call placed on Participants July 8th ($600,000). Two Mark II Skimmers arrived on site July 8th. Two Vikoma Sea Packs arrived on site July 21st. Telecommunications Task Force has been busy past two months. Negotiations for Black Jack Mtn.- Catalina is underway. Hired CPA and accounting firm.

AUGUST:

Field tested Acme Skimmers purchased air compressor for double purchased air compressor for double diaphram pumps. Field checking all gear for training to start early Sept. Aqua Contractors will perform training of other contractors. Ordered 150 Cyclonet (pair) at a cost of $300,000 for delivery Jan. 1, 1977. Hired legal counsel.

SEPT.:

Placed equipment on display (600 people) at Alameda Staging Service, Inc. people) at Alameda Staging Service, Inc. Made second contact with Navy in regard to Telecommunications on San Nicolas Island. Met with Mr. Shamback and USGS staff on Sept. 20th outlining equipment available - response times and proposed training programs. On Sept. 27, 28 and 29th conducted training programs on Vikoma Sea Pack.