bluuebunny/crossref_metadata_2025 huggingface dataset:
Remotely Controlled In-Situ Gas Lift on the Norne Subsea Field
Authors: Al-Kasim Ferid T. , Tevik Synøve , Jakobsen Knut Arne , Tang Yula , Jalali Younes
Published: December 2007

The paper discusses the design and installation of remotely controlled in-situ gas lift in the horizontal well B-4 BH on the Norne subsea field. The importance of proper design i.e.; sizing the valve small enough to avoid high pressure gas from the gas cap flowing back into the oil zone and large enough to optimise lift efficiency within the gas processing capacity is emphasized. Both a numerical and an analytical design analysis approach are presented. Examples of current and predicted well performance with and without gas lift are included.
A Case Study: Using Modern Reservoir Characterization to Optimize Future Development of a Mature Asset
Authors: Campanella John D. , Sonnenfeld Mark D. , Zahm Laura C. , Gilman James R. , Conrad Lara , Siemens Craig , Zaitlin Brian A.
Published: December 2007

Enhancements in software, hardware, expertise, data collection and interpretation have continued to improve the industry's ability to build detailed 3D geologic and dynamic flow models of the subsurface. These models in turn have improved our ability to make optimum reservoir engineering decisions for reservoir development. While such characterization has proved its worth for large assets over and over again, there continues to be much skepticism about the ability to use this process for mature or marginal assets.

This paper describes a field example showing how a truly integrated approach can shorten the time frame and reduce the cost of the characterization process. This ensures that all the available data is being used in an efficient manner to optimize future recovery.

Application of modern 3D reservoir characterization on mature fields is very problematic because of data quality issues, such as poor log quality, missing production data or lost cores. However, this lower quality data often provides bounds that are important in understanding the field performance and therefore should not be discarded. These data quality issues are addressed in this paper.

Additionally this paper shows how a truly integrated approach shortens the time frame for development of detailed 3D geologic and dynamic models. For example early conceptual flow modeling and engineering analysis provides valuable input for constraining the static geologic model.

Modern software tools and analysis techniques are greatly improving the ability to combine many scales of data. This provides a better understanding of the reservoirs and improved decision-making. The value of these tools is often a direct result of efficient analysis and visualization of the data and interpretations. These powerful capabilities should not be limited to large assets, as they can be cost effectively applied to mature properties also.
Integrated Reservoir Characterization and Simulation for Reservoir Management using a Web-Based Collaborative Technical Workflow Manager
Authors: Meng Hai Zui , Godbey Kevin S. , Gilman James R. , Uland Michael J.
Published: December 2007

Integrated reservoir characterization-simulation studies have repeatedly demonstrated reservoir management productivity gains. This is recorded in the literature1,2, and demonstrated by the increasing use of integrated 3-D project software for characterizing reservoir assets. The next level of productivity gains for integrated reservoir studies will be to improve the ‘technical workflow management’ of this complex, multi-disciplinary, iterative process. Technical workflow management will reduce the project cycle time, improve the quality of the reservoir model, provide early access to the most current interpretation, and help the operator select the appropriate level of reservoir technology for field optimization.

The future of cost-effective ‘technical workflow management’ lies in the appropriate use of the Internet and company Intranets to collectively manage project data, technical results, and the project objectives. The individual technical experts, who provide characterization-simulation results, can no longer expect to be working in the same office as the main asset team. Adaptive and distributed technical team members can provide an asset team with a competitive advantage by delivering over the internet, the best-in-class technology, skills, and workflows for collaborative team-based integrated technical studies.

This article discusses how a WEB based ‘technical workflow manager’ can provide an environment where all project disciplines can share project data, up-to-date technical interpretations, current and historical documentation, and can monitor the state of the technical project workflow. It introduces the concept of quality-control (QC) tools to allow review of the technical data and results at any stage of the project completion. The QC tools work without requiring detailed user knowledge or access to the technical software used to create the interpretation. This WEB based approach results in a dynamically maintained reservoir model, which is available on-demand to make business unit decisions using the most up-to-date technical interpretations from anywhere in the world.
Real-Time Downhole-Mixed Stimulation Fracturing Process
Authors: Scott George , Covatch Gary , Carrasco Art
Published: December 2007

A field-tested reservoir fracturing process comprised of carbon dioxide (CO2), fluid, and proppant was mixed downhole to generate a composite fracturing fluid that was modified in real time at the reservoir. This fracturing system provides numerous advantages over present industry fracturing practices, including reduced friction pressures and lower pumping-treatment pressures. In addition, this downhole-mixing process improves wellsite safety, reduces equipment horsepower requirements, and enables the operator to alter treatment mixture and proppant concentrations concurrent with the reservoir fracturing stimulation procedure in real time.

The first field application of this fracturing process was performed in September 2000 in an abandoned 12,300-ft Morrow gas well in the Sand Point field of Eddy County, New Mexico. The fracturing treatment consisted of methanol gel with 7,000 lb of bauxite proppant that was pumped down the annulus and blended above the perforations with 40 tons of liquid CO2 which was pumped down the tubing. A post-fracture tracer log showed that the treatment was placed in the objective reservoir as designed. Initial production from the well was approximately 250 Mcfd.

A common problem during fracturing is high surface treating pressures, which may prevent the pumping of fracturing treatments in their entirety. Typically, surface-mixed fracturing treatments are pumped at pressures that may exceed 10,000 psi. At these higher pressures, the stimulation treatment is aborted prematurely unless extra-strength tubulars are deployed. However, during the first downhole-mixed treatment, tubing pressures were observed at less than 6,000 psi, and casing pressures at less than 5,000 psi.

A second field application of the downhole-mixed fracturing system was performed in March 2002 in a stripper oil well (Delaware formation). Gelled lease oil, proppant, and CO2 were mixed downhole in an attempt to improve production from this well while avoiding fracturing out of zone. The detailed results from both test wells are presented in this paper.
Large-Scale Hydraulic Fracturing in a Frontier Area in China
Authors: Jin L. , Veltri D. , Krause D. , Weller T.
Published: December 2007

Four large-scale hydraulic fracturing treatments have been successfully conducted in a tight sand gas reservoir in Sichuan, China ranging from 300,000 to 700,000 lbs of proppant per well. Production of gas has been significantly enhanced. Previous hydraulic fracture operations conducted by both western service companies and Chinese Oil Companies did not meet the expected production rate to develop the field. This paper will focus on how the engineering challenges were identified and the designs implemented.
Fiber Optic Monitoring in Openhole Gravel Pack Completions
Authors: Corbett Gary , Fagervik Egil , Christie Stewart , Smith Bob , Falcon Keith
Published: December 2007

Fiber optic technology for real-time monitoring of down-hole well conditions is advancing rapidly in the oilfield. Discrete fiber optic sensors or fiber optic for distributed temperature measurements are relatively easy to deploy in conjunction with the production tubing string. Incorporating fiber optics into a gravel pack assembly is considerably more complex and requires several specialized equipment components. A method to mount the fiber optic conduit to the screen and protect the conduit during screen deployment, gravel packing and production is required. A sand control packer with feed- throughs for the conduit and compatible with crossover tool gravel placement methods is also required. Finally, a method to reconnect the production tubing to the gravel pack packer and establish a continuous fiber optic conduit from the surface to the end of the screen is needed. This paper describes the development and application of a gravel packing system that incorporates a conduit for fiber optics. The primary components of the system and lessons learned from a full- scale stack-up test are discussed. Technology gaps relating to fiber optic deployment tools and techniques are outlined.
An Account of Decline-Type-Curve Analysis of Vertical, Fractured, and Horizontal Well Production Data
Authors: Araya Anibal , Ozkan Erdal
Published: December 2007

This paper presents an account of decline-type-curve analysis of production data from vertical, fractured, and horizontal wells. It is discussed that the decline-type-curve analysis techniques presented in the literature are based on an approximate deconvolution of the production data and therefore have some limitations. In addition, decline-type-curve analysis inherits the limitations of both conventional pressure-transient and decline-curve analysis techniques. Because of the theoretical and practical limitations, decline-type-curve analysis may need to be supported by pressure transient analysis to yield meaningful and reliable results. In this paper, we also present an alternate approach to construct and analyze the decline type curves and present new decline type curves for horizontal wells. The application of the new horizontal-well decline type curves is demonstrated by examples.
Installation of In-Well Fiber-Optic Monitoring Systems
Authors: Kragas Tor K. , Pruett Eddie , Williams Brock
Published: December 2007

Over the past two years, there has been a dramatic increase in the number of permanent, in-well fiber optic monitoring systems installed worldwide. Systems have been deployed in a wide variety of locations, including the North Sea, Alaska, Gulf of Mexico, Middle East, and South America. These include installations on land and from offshore platforms, in environmental conditions ranging from the arctic to the jungle to the desert, to depths of over 22,000 feet, and to conditions up to 150°C and 15,000 psi. Fiber optic systems have been installed in wells for monitoring pressure, temperature, flow rate, phase fraction, and seismic.

This paper discusses recent experiences with installations of in-well fiber optic pressure, temperature, and flowmeter sensing systems. All aspects of the installations are described, including planning, logistics, run-in-hole during completion, and system commissioning. Elements common to and different from conventional monitoring system installations are examined. In particular, special requirements for fiber optic installations in different operating environments and lessons learned from past installations are discussed.
Simulation of Gas/Oil Gravity Drainage in a Stack of Interacting Blocks: Pseudo Relations for a Limited Number of Gridblocks
Authors: Wit Krijn , Clemens Torsten , Rijkels Lex
Published: December 2007

Naturally fractured carbonate fields contain a large portion of the world's light oil reserves. A number of these fields which are produced by gas/oil gravity drainage contain several billion barrels of oil.

To simulate naturally pervasively fractured fields, dual-permeability simulation programs are used. To achieve reasonable simulation times for huge fields, the number of gridblocks has to be restricted. However, reducing the number of gridblocks in vertical direction in a draining matrix column in gas/oil gravity drainage simulations lead to systematic underestimation of the oil drainage rate.

The simulation error due to limited number of gridblocks can be quantified. Knowing the error, the error can be corrected by modifying the (input) relation that links the oil drainage rate of a gridblock to its (average) oil saturation.

In this article, a procedure is presented to arrive at (pseudo) relative permeability relations for gridblocks in gas/oil gravity drainage simulations. By assigning to each gridblock in a stack a different pseudo relative permeability relation depending on its position in the stack, it is possible to largely reduce and in some cases completely remove the simulation error. This procedure enables using a very limited number of gridblocks in the vertical direction (in the extreme case only one gridblock).
Experimental Study of Two-Phase Pumping in a Progressive Cavity Pump Metal to Metal
Authors: Olivet Aurelio , Gamboa José , Kenyery Frank
Published: December 2007

Progressive cavity pump metal to metal has its two elements, rotor and stator, made from a metallic material. It has been demonstrated that this pump can reach an acceptable volumetric efficiency with high viscosity fluids. However, the performance of the pump with two-phase flow has never been investigated. There are not field or experimental tests which provide tools to predict the behavior of the pump in such applications. If progressive cavity pump metal to metal were able to handle high viscosity fluids with gas void fractions, as well as conventional progressive cavity pumps, it could be found a range of application for using this pump in heavy oil production. Its advantages would be valious, since it doesn't have the problems due to the use of elastomer stators.

In this research the progressive cavity pump metal to metal performance has been studied. Characteristic curves and instantaneous pressure profiles along the pump with single-phase and two-phase flow have been obtained experimentally. The results show that the internal slip with two-phase flow is a function of gas void fraction, differential pressure and rotational speed. Under some conditions an increase in volumetric efficiency occurs when the gas void fraction is increased. Instantaneous pressure profiles explain the changes of internal sealing lines when gas void fraction changes, also show that longitudinal pressure distribution along the pump have a linear behavior for single-phase and two-phase pumping.

The knowledges acquired with this research are useful for understanding the progressive cavity pump metal to metal performance in two-phase pumping applications and also can be used in the future for theorical modeling of the pump.
Stability Analysis of Continuous-Flow Gas-Lift Wells
Authors: Poblano E. , Camacho R. , Fairuzov Y. V.
Published: December 2007

Flow instability (heading) in gas-lift wells is examined in the present paper. A review of previous work done in this area is given. A model of a gas-lift well was developed. The model was validated using the field data obtained in tests of a gas-lift well in the Maloob field. Based on the model developed and existing stability criteria, theoretical gas-lift stability maps were developed and compared with field data. The effect of the injected gas flow rate, the injection port size and the tubing diameter on the flow stability was studied using the stability maps obtained in this work. It is shown that the proposed maps can be used as a simple and efficient method for predicting the stability threshold in designing gas-lift systems.
Construction of Fracture Network Model Using Static and Dynamic Data
Authors: Tamagawa T. , Matsuura T. , Anraku T. , Tezuka K. , Namikawa T.
Published: December 2007

This study reports a new process of constructing a discrete fracture network (DFN) model, which reflects various statistical properties of fractures extracted from static data such as borehole images and dynamic data such as pressure derivative curves.

A DFN model is constructed by generating a number of disc-shaped fractures based on their statistical properties. The process of constructing DFN model proposed consists of two streams. One stream is for the fractures with wide apertures, which work as main flow path of fluid. Another stream is for the fractures with narrow apertures, which work as main storage of fluid. In the each stream, a DFN model is constructed by applying fractal theory and geostatistics that define the size and spatial distribution of fractures, respectively. The overall DFN model is obtained by merging the two types of DFN models. Then, the DFN model is converted to a continuum model with equivalent permeable blocks based on cubic law and is evaluated by the fluid-flow behavior.

Japex has been operating the Yufutsu fractured basement gas reservoir since 1996. A total of approximately 8,000meters of electrical borehole images from eleven wells is measured to understand the fracture system. According to the proposed process, the DFN models are constructed. To evaluate the DFN models by comparing the simulated pressure derivative curves with the observed curve, flow simulations are carried out as a simulation of a single porosity type. The observed pressure derivative curve shows a concave shaped curve like a dual porosity behavior, but the curve never reaches the second flat state. Through the parameter studies of the statistical properties, which relate to the size distribution and the spatial distribution of fractures, the observed curve was successfully reproduced and the quantitative relationship between the fractures with wide apertures and the fractures with narrow apertures was found.
Encapsulated Breaker Release Rate at Hydrostatic Pressure and Elevated Temperatures
Authors: Lo Sho-Wei , Miller Matthew J. , Li Jack
Published: December 2007

Encapsulated breakers for water-based fracturing fluids have been widely used for the past decade. These breakers provide a delayed break because the reactive chemical is separated from the fracturing fluid by a water-resistant coating. Higher breaker concentrations can be used, resulting in improved proppant pack conductivity. However, the coating is not completely impermeable. The breaker material can release through the coating under certain conditions when placed in an aqueous environment.

This paper shows the breaker release rate as a function of temperature, hydrostatic pressure and aqueous fluid pH. A breaker release apparatus was developed, and tests were performed from 150°F to 225°F, 0 to 8000 psig, and fluid pH of 4, 7, and 9.5. The major findings were that the breaker release rate is a very strong function of pressure and temperature, but is independent of aqueous fluid pH. Fifteen percent of the encapsulated breaker is released after 6 hours at 150°F and 0 psig, whereas only 8% and 7% of the breaker is released at 2000 psig and 8000 psig, respectively. Sixty percent of the breaker is released after 1 hour at 225°F and 500 psig, while the 8000 psig breaker release is 12% after 1 hr. These findings suggest that tests evaluating the stability of fracturing fluids at low hydrostatic pressure conditions (such as using Model 35 or Model 50 rheometers) do not represent the actual breaker performance under fracturing conditions. Breaker schedules based on these low-pressure tests underuse encapsulated breakers and jeopardize the proppant pack cleanup process. Using the correlations developed in this study, it is possible to calculate the wellsite breaker schedule from low-pressure rheology tests using encapsulated breakers.

Polymer-induced fracture damage will be reduced and well productivity increased.
Maximizing Well Production with Unique Low Molecular Weight Frac Fluid
Authors: Peles J. , Wardlow R. W. , Cox G. , Haley W. , Dusterhoft R. , Walters H. G. , Weaver J.
Published: December 2007

Effective fracture length is the portion of the propped fracture that cleans up after hydraulic fracturing procedure and contributes to well productivity. Studies indicate that this effective length is often less than 10% of the total propped fracture length. A large portion of our fracture stimulation dollars are wasted!

This paper presents a comparative well study performed in the Cement field in south central Oklahoma. Stimulation of the Springer Sands using hydraulic fracturing with conventional low polymer fluids was compared with the use of low molecular weight polymer fracturing fluid. The depth of the three Springer Sands (Cunningham, Britt, and Boatwright) ranges from 12,500 feet to 15,500 feet and have an average permeability range of 0.1 to 5.0 md.

This evaluation includes several components. Well production history matching and pressure analyses are used to determine effective fracture length. Results of these analyses are compared with calculated values based on laboratory generated cleanup data for the two fluid systems. Flowback rate, pressure, accumulated volume, viscosity, and polymer content were collected following the fracture stimulation treatments.

The fluid systems compared in this study are a conventional low polymer system with gel breakers and a new, low molecular weight polymer system that requires no breakers. Both fluids use borate cross-linking chemistry. The low molecular weight fluid system creates transient, high molecular weight polymer chains at higher pH conditions. After exposure to the formation minerals, the pH drops and it reverts to a clean, nearly Newtonian, low viscosity fluid that causes little conductivity damage.

The results of this study show that the use of low molecular weight fracturing fluid provides significant improvements in the effective fracture length over conventional low polymer fracturing fluids. Simple engineering tools have also been developed to evaluate both fluid and proppant selection and job design to achieve improved well performance. It also demonstrated that improved recovery of the fracturing fluid can be achieved at excellent rates without the use of conventional gel breakers.
Mechanical Response and Characterization of Well Cements
Authors: Philippacopoulos A. J. , Berndt M. L.
Published: December 2007

It has been identified that well cement design and selection procedures require more sophistication than simple compressive strength criteria. In order to meet this need, it is necessary to characterize experimentally certain mechanical and thermal properties of cements and to develop appropriate modeling techniques for subsequent structural response analysis. This paper examines the properties of different well cements and how tensile strength can be improved by addition of fibres. The transient thermoelastic response of the various cements was investigated by finite element models to determine how stresses can vary with time and location, in addition to material properties.
Productivity Decline in Oil Wells Related to Asphaltene Precipitation and Emulsion Blocks
Authors: Kokal Sunil , Dawood Naseem , Fontanilla Jerry , Al-Ghamdi Abdullah , Nasr-El-Din Hisham , Al-Rufaie Yousef
Published: December 2007

A few oil wells in a Saudi Arabian field have shown significant oil productivity decline in recent years. A few of them have ‘died’ prematurely while others have become intermittent producers. It has been noticed that the oil productivity decline is aggravated with water encroachment. The oil productivity decline has come about with relatively low water rates and without any significant drop in reservoir pressure. These wells have low productivity index (PI) resulting in relatively low flowing bottom hole pressures (FBHP).

This paper presents the results of an investigative case study to determine the causes of productivity decline in these wells. A multi-disciplinary team was set up with engineers and scientists from reservoir management, production engineering and the R&D Center for the investigative study. The team focused on multiple aspects including reservoir and production engineering, as well as a comprehensive laboratory and field investigation.

The results of this study indicate that one of the main causes of productivity decline in these wells is related to asphaltene precipitation and the subsequent formation of tight emulsions downhole. The emulsions block the pore throats and cause formation damage leading to productivity decline. Another factor that further aggravates the productivity of these wells is poor rock quality in the area. Possible causes of formation damage due to inorganic scaling, and leakage and mixing of gas from a deeper reservoir have been eliminated.

Well test analyses on some of the affected wells shows the formation damage mechanism in the affected area is further aggravated by poor reservoir rock quality. The time-lapse pressure transient analysis also indicates a deterioration of skin and productivity with time.

Based on these findings a special solvent treatment was recommended and designed as a pilot trial for one of the dead wells. The treatment included squeezing xylene and demulsifier to dissolve the asphaltenes and break the tight emulsions around the wellbore area. The treatment resulted in only a slight improvement in the productivity index and the well died after a few days. Currently a stimulation treatment with acid and demulsifier is being implemented in selected wells. The results of the field trials will be described in the paper.
Development Well Testing Enhancement Using a Multiphase Flowmeter
Authors: Mus E. A. , Toskey E. D. , Bascoul S. J. F. , Barber E. C.
Published: December 2007

The use of a multiphase flow meter in the well testing facilities has yielded significant enhancements for the development program of the Girassol deep offshore field. Well performance assessment is improved by the complete data coverage and better accuracy the meter provides. Operating time is reduced because the well test data is obtained during the clean-up period. Use of the meter also allows a better control of the well clean-up duration and effectiveness. Overall, the flow assurance is improved because of the improved data quality given by the flow meter.
3 D Quantification of Vugs and Fractures Networks in Limestone Cores
Authors: Martinez-Angeles R. , Hernández-Escobedo L , Perez-Rosales C.
Published: December 2007

This paper presents the results of X-ray scans in vuggy-fractured limestone core studies to determine porosity rock distribution and residual oil and water saturations for mexican core samples. Iodine as the injecting fluid provided a means for detecting water saturation and residual oil saturation. X-ray Computerized Tomography (CT) was applied as an approach for oil and water saturation determination. The tracer (iodine) studies indicated that the water invasion increases with time until to get conduction porosity. CT scans measure the density distribution inside of vuggy-fractured cores and block models samples during X-ray CT laboratory experiments. Firstly, an image processing method for determining, simultaneously, some of basic geometrical characteristics of homogeneous and vuggy-fractured porous media such as secondary porosity, specific surface, mean pore width, mean block thickness, mean fracture width, and absolute permeability is applied in order to characterize the core. Then, oil recovery mechanisms from vuggy-fractured reservoirs were studied because of the large reserves contained in such formations- The estimation of saturation of residual oil is fundamental to oil recovery from vuggy-fractured reservoirs under primary and enhanced recovery processes of practical interest. Saturation of residual oil depends of several petrophysical parameters such as conduction porosity, stagnation porosity, cementation exponent and fluid properties like viscosity of wetting and nonwetting phases. In this paper we present our recent work on imaging dynamic characterization in a vuggy-fractured core (calcareous) with X-ray tomographic techniques. We also perform forced displacement experiment to get two liquid phases inside the vuggy-fractured limestone core.
Laboratory development and Successful Application of a Micelle Dispersions System to EOR
Authors: Tian Yuqin , Wang Lushan , Lv Xihui , Li Jiyong , Li Gongrang , Zeng Xianxiang
Published: December 2007

The laboratory performance properties of the colloidal dispersion system are described in the proposed paper. This paper deals with the improvement and application of a new technology to EOR. This technology is applicable to high salinity, high temperature and severe heterogeneity reservoir.

The essence of this technology is to decrease the water cut of production wells and attain the result of oil production and recovery enhancement by injecting an improved micelle dispersions system. According to lab test, this colloidal dispersion system is a pseudoplastic fluid with temperature tolerance, salinity tolerance, shearing resistance, stability and low cost. The lab experiment result shows oil recovery is improved by 8—10%.

The information of lab study and field application relative to this technology has been presented at the 2000 International Symposium on Petroleum Engineering. The previous technology has a defect of crosslinking to polymer's wide applicability, now this system has been improved in its properties. The new micelle dispersions system can satisfy all polymer in use and form stable weak gel system. It can keep stable when reservoir temperature is 90°C, water salinity is 80000mg/L (Ca2++Mg2+≤ 2000mg/L).

A pilot was conducted in fault—block Xin 50 of Dongxin oil field. There are 4 injection wells and 7 corresponding production wells.in the area The viscosity of aimed formation oil is 80mPa.s, the temperature is 90 °C, the salinity of reservoir is 44100mg/L, well spacing is 300m. Some production wells were effective after 2 months injection during the successive injection of this improved micelle dispersions system. Water cut of typical effective well was decreased by 34.1%. Oil production per day increased 30 ton.

Pilot test shows that this technology has better enlarge commercial application potentiality and economic value. It will be applied in others similar blocks on great scale in the future.
ESP Design Changes for High GLR and High Sand Production; Apache Stag Project
Authors: Muecke N. B. , Kappelhoff G. H. , Watson A.
Published: December 2007

Initial ESP designs for the Stag oil field, located on the Australian Northwest Shelf, were based on a low GOR, high viscosity, 19 API, crude oil. However, higher than forecasted gas rates and gas-oil separation in the 3300 ft long horizontal production sections resulted in flow from the reservoir in the form of slugs of gas and oil. Then, with the onset of water production, high volumes of produced sand compounded the problems. These two main issues, plus a rapidly declining reservoir pressure, have combined to present a challenging ESP production environment.

This paper reviews in detail the evolution of the completion design, focusing mainly on the ESP design, which initially ran for only 191 days, but now averages 511 days.

The intent of this paper is to provide advice to be considered when designing ESP completions for new reservoirs, to provide an example of a good completion design for handling fluids with high ratios of gas and sand, and finally, to provide information on new technology developments that have evolved from these learning experiences.
Innovative Through-Tubing Cement Packer Technique
Authors: Harris Marvin L.
Published: December 2007

Cement packers have been used for many years to access behind-pipe reserves above existing completions in wells with multiple completion targets. The basic function of the cement packer is to create a new annular barrier between an existing production packer and surface. They are typically used when it is not possible to set the production packer above the next zone of interest.

Most cement packer operations are performed rigless to minimize cost. However, in many of these operations, coiled tubing or hydraulic workover services are used for the placement of the cement packer. Although these costs are significantly less than the cost of a rig, they still represent a major source of the total cost to perform the cement packer operation. In certain circumstances, coiled tubing and hydraulic workover services may not be possible because of space limitations, equipment availability, or cost restrictions. Elimination of these services can significantly reduce the cost and complexity of the operation, and improve the economics for the project. This paper presents a technique that can be used to perform a cement packer using only wireline (slickline and electric line) and pumping services.

A case study of several successful cement packer recompletions using this technique is also presented at the end of the paper. The technique has been proven successful in wellbores with gas lift mandrels, in cases where the circulating holes for the cement packer are above or below the zone of interest, in producers and injectors, and in deviated wellbores.
Engineering Aspects of Geological Sequestration of Carbon Dioxide
Authors: Ennis-King J. , Paterson Lincoln
Published: December 2007

Injection into geological formations is a technical option for decreasing carbon dioxide emissions to the atmosphere. Several key factors influence the performance and long-term integrity of injection into deep saline formations. Accurate representations of the physical properties of carbon dioxide have compiled and use to determine the theoretical storage density at typical sub-surface conditions, and the amount of energy that would be expended in injecting the carbon dioxide (whether pure or mixed with other gases), leading to an estimate of the net reduction of emissions. Detailed computer simulations indicate that the distribution of the injected carbon dioxide is initially dominated by gravity segregation, relative permeability effects and the permeability anisotropy of the saline formation. Post-injection, important effects occur which are not taken into account in conventional petroleum reservoir simulation. Convective mixing is predicted to occur, which greatly accelerates the dissolution of carbon dioxide in the saline formation water. This unusual phenomenon arises from the increase in the density of brine when saturated with carbon dioxide. Complete dissolution of the injected carbon dioxide is predicted to occur over hundreds to thousands of years, depending significantly on the vertical permeability of the formation and the geometry of the top seal. Reactions between the carbonated water and the formation also increase the rate of dissolution. If the chosen site is not a structural trap but a gently dipping regionally extensive formation, then the carbon dioxide can migrate up to tens of kilometres from the injection site, depending on the angle of dip and the horizontal permeability. However, convection and dissolution can still keep the carbon dioxide confined. This theoretical analysis has been developed as part of the Australian Petroleum CRC's GEODISC program, and is being used to assess the suitability of proposed sites for carbon dioxide sequestration.
Influence of the Horizontal Well Length upon Production Rate and Water-Cut Performance in Regular Field Development Systems with Horizontal Wells
Authors: Mukminov I. R.
Published: December 2007

To date, the problems of current productivity and water-cut performance calculations for horizontal wells in different regular field development systems have been poorly studied, and the main method of investigation has been the numerical one. In sheet deposits of Western Siberia, Russia, which have nearly equal mobility ratios of oil and injected water, a nearly frontal drive is observed. This aspect is discussed in the present paper.

The report presents a precise analytical solution of steady-state fluid filtration problem in six regular development systems where horizontal wells are applied. The solution allows the derivation of analytical expressions for the rate, pressure field and filtration velocities, water-free operation time, flooding factor during water-free and water periods of operation, water-cut performance for horizontal wells, and flood front.

Graphic illustrations allow a visual evaluation of the operation character for different sections of the horizontal well, location of unusable zones in a number of well patterns with horizontal wells applied.

The paper shows the influence of the horizontal well length, distance between wells in rows and between well rows upon rate, velocity field of filtration, water-cut time, flooding factor, water-cut dynamics for horizontal wells, and the form of the flood front.

A quantitative range of effective and ineffective applications of horizontal wells is given for each system, depending upon the length of the horizontal section, injection well type (vertical or horizontal), distance between wells in rows and distance between well rows.

The author believes that the paper is very important for a better understanding of flooding processes in field development systems where horizontal wells are applied, and it gives an idea of the way various parameters that characterize the geometrical location of horizontal well systems, influence the deposit operation parameters. The author uses the results to construct a rational 3D hydrodynamic model of Western Siberian reservoirs with reference to a detailed description and the number of cells.
Advanced Production Logging Technology for More Accurate Flow Profiling-Case Studies from the Gulf of Suez
Authors: Elshahawi Hani , Mostafa Hanaey
Published: December 2007

The already complex job of diagnosing production problems and flow profiling in a multiphase environment is further complicated by the complex flow regimes encountered in horizontal, highly deviated, and slim wells. Accurate holdup measurements are needed to clearly identify the first point of hydrocarbon or water entry, and independent oil, water and gas flow rates versus depth are needed to obtain overall downhole flow rates and to identify production from each perforated interval. Qualitative fluid identification is also needed to help determine the type of fluids contributed by each zone. Finally, imaging of the well bore is needed to detect cross flow, circulating flow, and phase segregation.

The latest generation of production logging tools has traditional measurements such as pressure, temperature, density and spinner redesigned to deliver superior accuracy and resolution. New sensors such as local electrical probes for holdup have been collocated with the spinner and an integrated X-Y caliper to provide accurate answers in complex flow regimes. Introduction of this advanced production logging technology in the fields of the Gulf of Suez has represented a virtual breakthrough in the use of production logging in that company. This has enabled the diagnosis and treatment of problems previously undetectable and hence unsolvable due to excessive well deviation, high water cut, or mixing of water injected and formation waters. Correct diagnosis has resulted in proper work over planning and application and, in turn, to improved reservoir management practices.

This paper describes this new technology and presents case histories in which operators in the Gulf of Suez have successfully employed revolutionary production logging improvements to provide timely cost-effective diagnosis for some of the most challenging well production problems.
High Membrane Efficiency Water-Based Drilling Fluids: Alternatives to Invert Emulsion Fluids for Drilling Troublesome Shale Formations
Authors: Tan Chee P. , Drummond Calum J. , Mody Fersheed K. , Tare Uday A.
Published: December 2007

A major collaborative project was undertaken to develop novel environmentally acceptable water-based drilling fluids with high membrane efficiency to help meet the future requirements of the petroleum industry. This paper describes the rationale of the project, the fundamental understanding of osmotic membrane generation in shale that lead to the development of the drilling fluids, and the practical guidelines for maintaining shale stability with the drilling fluids. Specialised test equipment, including membrane efficiency screening equipment, and test procedures were developed for simulation of key drilling fluid-shale interaction mechanisms. More than 300 membrane efficiency screening tests were performed on Pierre II shale samples to screen a wide range of novel compounds for their membrane generation capacity in the shale. Typical examples of the tests conducted with three novel compounds that generated moderately and highly efficient membranes are presented and discussed. The results demonstrate that some of the compounds are capable of generating membrane efficiencies of between 55% and 85%. The new generation of water-based drilling fluids that have been developed performs essentially like oil-based muds in terms of shale stabilisation. Practical mud design guidelines that have been developed can be used to optimise the drilling fluid design, in terms of mud weight, salt type and salt concentration, to manage efficiently time-dependent wellbore instability in troublesome shale formations.
Producing More Than 75% of Daqing Oil Field's Production by IOR, What Experiences Have Been Learnt?
Authors: Wang Demin , Sun Yingjie , Wang Yan , Tang Xuping
Published: December 2007

The annual production of Daqing Oil Field reached 50 million tons (1 million bbl/d) in 1976 and has maintained stable up to the present for 26 years. In year 2001, the annual production produced by wells drilled before 1975 is only 12 million tons, the remaining 38 million tons, which amounts to about 76% of Daqing's total production mainly comes from IOR. The large scale implementation of IOR not only increased the production, but also more than doubled the recoverable reserves of Daqing from 1 billion tons to 2.2 billion tons.

A large amount of actual field data and production history curves are used to show the results on the entire field of different IOR methods on multi-zone stacked reservoirs and single zone thick reservoirs, including the increase in production and recovery, decrease in water-cut and influence on production costs of the entire field.

The total results of IOR implemented on large areas of the oil field (each having more than 1 thousand wells) and on the entire field (more than 50 thousand wells) over a long period of time of more than 30 years is shown. The change in production rate, recovery, water-cut and production costs are also shown. How IOR can maintain the production stable and increase the reserves at low production costs is explained.
Producing by Polymer Flooding more than 300 Million Barrels of Oil,What Experiences Have Been Learnt?
Authors: Wang Demin , Cheng Jiecheng , Wu Junzheng , Wang Yan
Published: December 2007

In 1996, Daqing Oil Field started industrial scale polymer flooding. The production by polymer flooding since then has rapidly increased. The annual production by polymer flooding in year 2001 was more than 70 million barrels (bbl), cumulative production more than 300 million bbl and more than 3 thousand wells are on polymer flooding. Much experience has been learnt on large scale polymer flooding in these 6 years, including: actual recovery in the field; major factors that influence the recovery and methods to increase the recovery; measures to obtain a uniform polymer flood front; and how to lower the costs of producing crude oil by polymer flooding.
Improvement of Permeability Prediction for Carbonate Reservoirs Using Well Log Data
Authors: Babadagli T. , Al-Salmi S.
Published: December 2007

The prediction of permeability in heterogeneous carbonates from well log data represents a difficult and complex problem. Generally, a simple correlation between permeability and porosity cannot be developed and other well log parameters need to be imbedded into the correlation. The first part of this paper covers an extensive review of the existing correlations in literature. The use of porosity and other petrophysical properties of rock in permeability prediction is discussed for carbonaceous rocks. This discussion also covers the usefulness of a wide variety of correlations developed using pore (Kozeny-Carman, percolation, and fractal models) to field scale models (well logs).

In the second part of the paper, a case study was presented. The data are obtained from a complex carbonate field in Oman. Conventional and non-conventional (mainly Nuclear Magnetic Resonance, NMR) well log data are evaluated to seek the parameters reflecting a good correlation with permeability. After testing each independent variable against core permeability, the variables yielding the highest correlation coefficient are included in multiple regression analysis. Data collected from seven wells are used to obtain the permeability correlations for the whole field and four geological units separately. The test of the correlations is achieved through the comparison of the estimated permeability values to core permeability. Finally, the correlations are compared with the core permeability of the eighth well (data from this well are not included in the development of the correlation) for validation. The correlations are obtained for the four geological units. Two of these units responded well to conventional well log data. Other two units yielded reasonable correlations only with NMR log data.
Field Trial of Multiphase Metering Systems in Light Oil Steam Flood Applications, Minas - Indonesia
Authors: Uphold Donald D. , Siboro Paulus D. , Kouba Gene E.
Published: December 2007

This paper illustrates performance and best practice of compact multiphase metering systems that have been operating for 2-years in the light-oil steamflood pilot in Minas-Sumatra. These results motivate the need for life-cycle risk models integrating new technologies to meet customer needs. In some cases, low-cost new-technology may not be the best choice. If multiphase metering systems are suitable, then a unified systems' vendor should be included on the team during all phases of the project, especially early on to support quality assurance during integration of sub-systems, and later during commission and operation to support quality control of the complete metering package. In this paper, we present two similar types metering systems for two different types of applications: 1) well-test measurement, and 2) bulk production measurement. Both metering systems are of the partial separation type and use a compact gas-liquid cylindrical cyclone separator, or GLCC© (copyright by The University of Tulsa, 1994). When constructed these were the largest GLCCs and are still believed to be the largest operating GLCCs in the world. After the produced fluids are separated into individual gas and liquid streams, each stream is volumetrically metered and then recombined. The liquid level in the separator is controlled by an innovative gas-liquid dual-mode control scheme. For water-cut measurement, the well-test system uses an on-line instrument whereas the bulk metering system uses a physical fluid measurement based on sampling and analyses. Field data and suggested modifications to achieve suitable operation are presented. In particular, we focus on the impact and uncertainty of higher than expected sand concentration, watercut, flowrate, pressure & temperature on the original design, and consequently discuss the specific changes we made to address these challenges.