bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nitrogen Injection in the Cantarell Complex: Results After Four Years of Operation
Authors: Sánchez J. L. , Astudillo A. , Rodríguez F. , Morales J. , Rodríguez A. 
Published: December 2007

Abstract
The nitrogen injection project in the Cantarell Complex, offshore Mexico, implemented in May 2000, has been the most ambitious pressure maintenance project around the world regarding incremental oil, production rate, nitrogen injection rate, and investment.
In this paper, the main drivers and objectives of the project, along with key issues that have been taken into account to guaranty success, are reviewed. A description of the data acquisition program implemented to monitor reservoir performance during nitrogen injection is discussed and results analyzed.
The pressure-production behavior of the reservoir during nitrogen injection is presented and results obtained after four years of operations are assessed, along with additional field development and benefits from updating and increasing facilities.
Numerical Modeling of Advanced In-Situ Recovery Processes in Complex Heavy-Oil and Bitumen Reservoirs
Authors: Card C. C. , Close J. C. , Collins D. A. C. , Sammon P. H. , Wheeler T. J. , Fortson N. G. 
Published: December 2007

Abstract
As development activities in heavy oil and in situ bitumen deposits have accelerated, the challenge of forecasting the performance of in situ recovery processes at field scale has increased exponentially.
Delineation drilling results make it apparent that these deposits are highly complex and three-dimensionally heterogeneous. Heterogeneity has a significant impact on the effectiveness and economics of the recovery process.
Many experienced operators are recognizing that in addition to the static complexity of the reservoirs it is necessary to consider the dynamic stress state in the regions undergoing production. Geomechanical factors are significant and must be built into any realistic numerical simulation of recovery processes.
It has become apparent to operators that modeling single well-pair operations may be misleading, and seven to ten well-pair models are now quite common.
All these factors result in increasing size and complexity of numerical simulation models.
Reservoir simulator developers have responded with two technologies to achieve reasonable run times in these large and complex models. The combined use of 64-bit symmetrical multiprocessor computers and dynamic grid refinement will be discussed and compared against traditional simulation methods.
This paper will provide examples of the application of these leading edge technologies for in situ oil sands development in the Surmont area of the Athabasca deposit.
Designer Casing for Deepwater HPHT Wells
Authors: Miller Richard A. , Payne Michael L. , Erpelding Peter 
Published: December 2007

AbstractDeepwater high pressure, high temperature (HPHT) drilling environments present difficult challenges to well engineers. Typical deepwater pore pressure and fracture gradient profiles result in a narrow drilling window that can lead to seven to nine casing points. The high cost of these wells demands a high rate completion for economic payback, which defines the size of the production casing and liners. Drilling casings are restricted by the standardized 18-3/4" through bore diameter dictated by high pressure wellhead housings, blowout preventers, and riser systems. Furthermore, high pressures require thick wall casing, especially if sour service materials are specified. Satisfying all of these pressure and geometrical constraints requires some unconventional practices.Current and emerging technologies offer several ways to address this design dilemma. Riser-less drilling can be an effective way to delay running the high pressure wellhead, allowing for additional large diameter casing seats. Dual gradient drilling is a concept that can decrease the number of required casing points. Solid expandable liners provide a way to add or push casing points without the geometry impact of a conventional string. Managed pressure drilling may also show promise for eliminating a seat. However, heavy reliance on these new technologies may run counter to the guiding principle of keeping HPHT wells as simple and reliable as possible.This paper presents the concept of using conventional oil country tubular goods (OCTG) in unconventional sizes to increase the number of available casing points in deepwater wells. The method has several advantages in the areas of performance and reliability compared with the previously listed technologies. The decades of industry experience with conventional OCTG make the technology especially appropriate for containing high pressures and sealing off trouble formations.Related issues such as manufacturing lead time, costs, connections, and hangers are discussed. Several HPHT examples are included to illustrate the trade-offs with other design options.
Alternatives for High Strength Materials in Sour Environments
Authors: Turconi G. López , Fukui T. , Ono T. , Pérez T. 
Published: December 2007

Summary
Typical environments foreseen in HPHT wells put a high challenge for properties required for materials. Strength levels create severe limitations to improve toughness, resistance to hydrogen embrittlement and other corrosive agents responsible of both general and localized corrosion. High temperature service reduces the alternatives, because of effect on corrosion and also the reduction in strength at temperature. Internal pressure and well depth create a combination of stress that would lead to requirements of heavy wall thickness for tubulars. This, in turn, is a challenge for seamless tubular manufacture with actual production routes, particularly in the field of hot deformation and heat treatment.
Progress has been made in the design and production of low alloy carbon steel that somehow has reached the limit of actual metallurgy science. Other material alternatives, in the field of stainless steels and other corrosion resistance alloys can be also explored.
Another particular point is the development of methods for properties assessment in the expected environments. The reproductions in laboratory conditions, and the correlation with those in the field, are areas of research and test development.
The paper shows the alternatives that exist in the field of material selection, through the comparative evaluation of mechanical and corrosion properties for a range of materials through normalized test procedures and other research activities.
Disposable Wells: A Monobore One Trip Case Study.
Authors: Chapman W. 
Published: December 2007

Abstract
This paper will discuss a Monobore one trip cement through completion system. The system was designed to add artificial lift capabilities and improve safety to short life monobore wells. The disposable well bore concept is gaining popularity in regions worldwide. This paper will also discuss case histories including operation issues and problems and how they were solved.
Operational procedures will be outlined to effectively demonstrate, and discuss the decision making process when determining the most cost effective candidates for this technology.
Evaluating Permanently Installed Fiber-Optic Distributed Temperature Measurements Using Temperature-Step Resolution
Authors: Hadley M. R. , Brown G. A. , Naldrett G. 
Published: December 2007

AbstractThe fiber-optic distributed temperature sensor (DTS) has emerged in recent years as a valuable tool in the oil and gas industry. From intervention services, to permanent wellbore installations, steam-flood, sub-sea installation, and flow assurance, the number and diversity of DTS applications has steadily grown. Supply of DTS instruments, fibers, and services is a lively and growing market which has attracted multiple competing suppliers.The DTS measures temperature using a length of optical fiber as the sensing element. Each measurement takes the form of a temperature trace or profile comprising samples from regular intervals – usually about 1m – along the entire fiber. Each profile is generated by averaging the weak optical signals that carry the temperature information, over a period of anywhere between a few seconds and a few hours.While a temperature profile is similar to a temperature log, the simultaneous measurement of all data points and regular repeated measurements give new opportunities for wellbore temperature analysis. Over the last few years, existing techniques have been modified and new ones developed to capitalize on DTS temperature profile measurements. These include measurement of flow rate in producing and injecting wells, and monitoring gas lift valves, as well as monitoring steam flood and SAGD wells. (References [1], [2], [3], [4], [5], [6], [7], [8]).
An ALS Solution to Low-Pressure SAGD
Authors: Wiltse D. J. 
Published: December 2007

Abstract
The trend for SAGD in Canada is towards low pressure steam injection. The primary reasons for this trend are both economical and operational in that low pressure translates to lower operating costs and improved recoveries.1 Low pressure SAGD also requires an artificial lift system (ALS) in order to achieve desired production rates.
This paper will discuss a unique ALS that was specifically developed for the lifting challenges associated with low pressure SAGD - the Hydraulic Gas Pump (HGP). This rodless technology utilizes high pressure gas to positively displace production fluid. At the time of the writing of this abstract, the HGP had passed rigorous lab testing and surpassed all performance expectations in a test well. Furthermore, it is currently being field-tested in a SAGD well in Canada. The paper concludes with the actual HGP field-test performance results from that well.
Initiatives for Improving Oil Recovery at Guntong
Authors: Kueh S. R. M. , Mohamad W. N. W. , Sim C. -H. 
Published: December 2007

AbstractThe Guntong field is one of the largest oil fields in the Malay Basin. With almost twenty years of production history and currently at 80% depletion, Guntong production has been on the decline since the late 90s. Despite the complexities resulting from its multiple stacked reservoirs that are developed by 150 wells, and the challenges of maximizing oil recovery from a mature offshore field, the various oil recovery improvement measures implemented at Guntong have successfully resulted in the addition of almost 80 million barrels of oil to the overall field recovery within the last five years.This paper is an overview of these initiatives which include workovers to decommingle selected reservoirs and perform acid stimulations, in addition to three infill drilling programs that were conducted within a span of three years. A fourth infill program, requiring a new satellite platform, is scheduled for completion in 2005. Positive results were also achieved by revising the field's reservoir pressure maintenance program along with optimizing reservoir management strategies such as water injection patterns.The underlying key to the success of these efforts has been the holistic approach in analyzing the field data. A more comprehensive understanding of the reservoir behavior was achieved by integrating production data, geology, reservoir engineering as well as findings from the recent infill programs. A more accurate representation of the reservoir behavior was attained through iterative comparisons between the geologic description updates and the results derived from the reservoir simulation models. Predictions from these models, which were further supported by seismic timelapse and AVO analyses, have led to the successful identification of bypassed oil regions within the field. Moreover, the availability of reliable simulation models was also instrumental in testing out and fine-tuning reservoir management strategies before their implementation.
Controlling Water Risks in Extra-Heavy-Oil Environments
Authors: Pereira E. , Vincent G. , Ichbia J.-M. , Johannessen A. 
Published: December 2007

Abstract
SINCOR is one of the major operators of the Orinoco Belt in Venezuela (Figure 1). It produces 8.5°API gravity of Extra Heavy Oil (EHO) with a viscosity at reservoir conditions between 1800–3500cP. The EHO is upgraded in Venezuela to market of high quality 32 °API synthetic crude oil. The geological context is fluvio-deltaic with high sand content, very good permeabilities and large regional aquifer. Before start-up, the impact and strength of the aquifer were identified as major risks for both production and reserves due to extreme viscosity contrasts.
The first phase of development is completed and includes more than 300 horizontal wells. SINCOR produces 200.000 bbl EHO/d today. Prior to a second development phase, answering to the question: "what have we learnt of the aquifer risk?", should help making the next development phase more efficient. Some of the main lessons learnt are: Water entry is very local in the wells.Risk of water interference between wells in the same sand is high.Wells accumulate large volumes of EHO after water breakthrough.Aquifer pressure support is lower than expected.
Thorough monitoring policy of wet wells allowed evidencing some specific characteristics of this EHO field: Water banking at well level.Link liquid rate/water cut… favorable to EHO.Data acquisition allowing partial quantification of aquifer strength.
A production policy was then implemented that allowed optimizing both production potential and reserves of existing wells. To maximize reserves, water handling capacity (WHC) is adjusted with time and the future drilling sequence will account for both planned WHC modifications and risks of water interference. Phased development coupled with thorough monitoring policy lead to understand better the behavior of EHO crude in unfavorable environment. Today, this allows SINCOR to adapt its development plan to improved control of the risks linked to the aquifer.
This paper demonstrates the added value of an appropriate integrated monitoring strategy that optimizes reservoir performance and provides lessons for further development plans.
Development of a Chemical Treatment for the Management of Wellbore Tar Adhesion
Authors: Perez G. P. 
Published: December 2007

Abstract
Incursion of subterranean tar into the wellbore during and/or after drilling has the potential to result in a variety of problems. If the tar is soft and deformable, it may ‘refill’ the wellbore and require additional drilling time and casing operations. An additional problem is adhesion or accretion of the tar directly onto the drillstring or bottom-hole-assembly (BHA). Such fouling of the drillstring/BHA often requires unplanned tripping to physically remove the adhered tar. It is also conceivable that the tar-related problems may ultimately result in the hole being plugged and abandoned. For these reasons, an approach has been developed to (1) emulate the reported wellbore accretion, and (2) develop lab-based approaches to help minimize/reverse the tar adhesion.
Investigation of tar accretion onto steel rods/tubes with a Gulf of Mexico tar was studied in a synthetic-based mud, to evaluate possible avenues of remediation. In addition to evaluating the conditions necessary to induce tar accretion in the laboratory, further studies were performed to affect reversal of the intentional accretion and also to help prevent initial accretion. Included are the results from the induced accretion and various additive-based attempts to mitigate the tar adhesion.
In order to induce lab-based accretion, it proved necessary to develop a testing method to emulate the scope of tar accretion observed in the field. This methodology is herein described along with the optimized fluid system. Of specific interest in this study is the ability to use this novel fluid either as a sweep, spot or additive as a means to help reduce the inherent ‘tackiness’ of the tar and thereby help reduce/prevent the adhesion to the emulated drill string. The fluid treatment developed is environmentally acceptable and uses a novel chemical composition which proved successful in reversing and preventing tar accretion under the laboratory experimental parameters.
Aspects of Reservoir Characterization From Waterflood Performance Data
Authors: Temizel C. , Ershaghi I. 
Published: December 2007

Abstract
Analytical techniques for prediction of waterfloods using homogeneous models are non-representative of behaviors observed for actual reservoirs. We have noted, however, that a scrutiny of such deviations can lead to estimation techniques for characterization of permeability contrast in a formation. This paper presents the results of studies conducted on the behavior of producing wells in a waterflood as affected by lateral variation in rock properties and formation stratification and crossflow. The purpose of the study was to derive useful reservoir characterization information from the embedded signals in waterflood performance data. Deviations from the predicted response for homogeneous reservoirs can serve to map the lateral reservoir properties.
For stratified reservoirs, we focused on the impact of a thief zone on the behavior of wells producing from sand-shale sequences. Using the theoretically predicted flood performance from analytical models for such systems, as calibrated by simulation studies, we developed the metrics for the estimation of a new parameter defined here as the thief zone heterogeneity index.
Characterisation and Emulsion Behaviour of Athabasca Extra-Heavy-Oil Produced by SAGD
Authors: Noik C. , Dalmazzone C. , Goulay C. , Glenat P. 
Published: December 2007

Abstract
The production of extra heavy oil (or bitumen) through the SAGD method (Steam Assisted Gravity Drainage) requires the generation and injection into the reservoir of a great quantity of steam. A typical value of the steam/oil ratio is around 3, which means that a 100,000 bopd development requires the injection of 300,000 bcwepd (barrels of cold water equivalent per day) of steam, and that a corresponding quantity of hot water will be co- produced with the oil. The production of extra heavy oil containing many active components with the tendency to form an emulsion combined with the high water-cut ratio (above 80%) leads to a phase separation process with specific issues. This study considers an extra heavy oil field produced in SAGD in Athabasca.
The objective of the study was firstly to characterise the produced fluids and then to analyse their tendency to form an emulsion under controlled hydrodynamic conditions. An innovative technique - Differential Scanning Calorimeter (DSC) - was used to characterise the emulsion. This method is able to define the water-in-oil or reverse emulsion nature and to quantify the water amount without sample dilution. DSC analysis combined with microscopy and image analysis treatments was used to determine the droplet size distribution. Reconstituted emulsions were then formed using a "Dispersion Rig" set-up that allows the simultaneous pumping of crude oil and water through a calibrated restriction in the pipe. The amount of energy dissipated to the fluids systems can be quantified due to the strict control of the hydrodynamic conditions. Consequently a relationship between granulometry distribution of the emulsion and the fixed energy or pressure drop can be established. The main experimental parameters investigated were the oil dilution and water-cut ratios.
It is concluded that there is a residual emulsion in extra heavy oil which has a very small average droplet size whatever the temperature and solvent dilution ratio. This small droplet size results in a difficult oil/water separation which is only possible either by addition of large quantities of additives at high temperature and with long residence time and probably by applying an electrostatic field.
Design and Analysis of Well Tests for Artificially Lifted Wells in Heavy-Oil Reservoirs
Authors: Estrada C. A. , Noble G. 
Published: December 2007

Abstract
The design and analysis of well tests for heavy oil producers is complicated due to both the mechanics of artificial lift and the properties of the fluids produced. Traditional analysis methods and assumptions used for light oils and flowing wells are only practically applicable and therefore special methods are required to ensure accurate reservoir information is obtained.
One mechanical complication for wells lifted by means of rod and progressive cavity pumps is the presence of a rising fluid level in the open annular space during the shut-in period. Wells are stopped at the surface because downhole shut-in is not feasible for both economic and mechanical reasons. Wellbore storage then becomes the determinant factor in the prediction of the shut-in period duration. Another complication is that the bottomhole pressure data is rarely directly measured due to the high cost of downhole recorders and their requirement to remove lift equipment. Pressure data is therefore calculated from fluid levels determined by acoustic methods.
The cases considered were heavy oil wells in Saskatchewan and Alberta. Completed in the Bakken and the middle Lloydminster sandstone reservoirs, they were at saturation pressure at the initial conditions. Some of these reservoirs have been subjected to waterflooding after a period of primary production. Therefore, in addition to the mechanical condition of the well, multiphase flow and fluid property variation make the traditional pressure analysis inaccurate. Oil viscosity, for example, could not be treated as a constant in the well drainage area because of the rather high pressure drop necessary to produce the wells.
Numerical simulation was conducted to evaluate the impact of multiphase flow and the variation of viscosity as a function of pressure at reservoir temperature in the pressure response of heavy oil wells. Based on simulation results, the applicability of pseudopressure functions in the well test design and analysis was evaluated.
Thermoplastic Properties of OCTG in a SAGD Application
Authors: Dall'Acqua D. , Smith D. T. , Kaiser T. M. V. 
Published: December 2007

Abstract
Engineering studies demonstrate the significance of post-yield mechanical characteristics of Oil Country Tubular Goods (OCTG) for governing the service limits of casing and liner products in Steam Assisted Gravity Drainage (SAGD) operations. New test methodologies have been developed to characterize these post-yield properties in a thermal environment at field-representative strain rates and static strain conditions. This provides a basis for quality assurance programs to verify that materials used in well construction meet the requirements for post-yield service in thermal operations.
This paper provides an overview of a quality program implemented for a major SAGD development in Western Canada. The program was designed to provide a statistically significant description of the thermo-mechanical properties of the tubulars used in the well construction. The overview includes a discussion of the material characterisation basis, the statistical design basis, a summary of material test results, and conclusions for ongoing testing in forthcoming phases of the project.