bluuebunny/crossref_metadata_2025 huggingface dataset:
Controlling Water Risks in Extra-Heavy-Oil Environments
Authors: Pereira E. , Vincent G. , Ichbia J.-M. , Johannessen A.
Published: December 2007

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

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

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

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

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

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.
Effects of Asphaltene Content and Solvent Concentration on Heavy-Oil Viscosity
Authors: Luo P. , Gu Y.
Published: December 2007

During a solvent-based heavy oil recovery process, significant viscosity reduction is achieved through sufficient solvent dissolution and possible asphaltene precipitation. In the second viscosity reduction mechanism, the heavy oil is in-situ upgraded as the asphaltene content in the produced heavy oil is greatly lowered. In this paper, the respective and synergistic effects of asphaltene content and solvent concentration on heavy oil viscosity are studied by measuring viscosities of heavy oil samples with different asphaltene contents and/or solvent concentrations. More specifically, a deasphalted heavy oil sample is obtained by using the standard ASTM method to extract asphaltenes from a crude heavy oil. Then reconstituted heavy oil sample is prepared by adding the extracted asphaltenes into the deasphalted heavy oil at a different asphaltene content each time and its corresponding viscosity is measured at the atmospheric pressure. It is found that the viscosity of such prepared heavy oil is sensitive to the asphaltene content. In particular, the viscosity of the deasphalted heavy oil is reduced by 13.7 times in comparison with that of the original heavy oil at T=23.9°C. This indicates that high asphaltene content results in high viscosity of the heavy oil. On the other hand, the viscosities of propane-saturated heavy oil samples with different asphaltene contents are measured at high pressures. As the equilibrium propane concentration reaches certain value, the viscosity of the crude heavy oil-propane system is reduced by almost two orders. This result shows that solvent dissolution plays a dominant role in heavy oil viscosity reduction. When the equilibrium propane concentration is high enough, all the three reconstituted heavy oil-propane systems have extremely low viscosities. In this case, effect of asphaltene content on heavy oil viscosity becomes negligible.
A New Semiautomatic PVT Apparatus for Characterizing Vapex Systems
Authors: Freitag N. P. , Sayegh S. G. , Exelby R.
Published: December 2007

Knowledge of fluid properties is critical to the design of Vapex projects and other enhanced oil recovery processes that use solvent vapor extraction, yet very few pertinent data exist in the published literature. This paper describes a new apparatus for the efficient and accurate measurement of the physical and phase behaviour properties of mixtures of heavy oils and solvents such as propane and butane. The apparatus combines advanced capabilities that make it superior to conventional designs: The automated functions improve the speed at which the data are acquired and reduce operator error. Inline density and viscosity measurements add the capability of multi-phase detection. High-pressure filtration permits measurement of asphaltene and wax precipitation at reservoir conditions. Dual gasometers allow accurate measurements of gas solubility over a wide range of solvents and reservoir pressures. Sub-ambient temperature control makes it suitable for Canadian operations.

The apparatus was tested against published measurements for the n-hexadecane-carbon dioxide system, and then used to gather a comprehensive suite of data at two isotherms for a Lloydminster heavy oil-propane system. Random scatter in the resulting data was very small. The equipment is well suited to the acquisition of fluid property measurements for both field design and correlation purposes.

With the improvements in both the precision of measurements and the speed of operation offered by the new equipment, it was possible to test some assumptions used in measuring vapor-liquid equilibrium in heavy oil-solvent systems. The results suggested that a noticeable uncertainty may be associated with conventional methods used to determine saturation pressures in these systems.
Advanced Electrostatic Technologies for Dehydration of Heavy Oils
Authors: Thomason W. H. , Blumer D. J. , Singh P. , Cope D. P. , Zaouk M.
Published: December 2007

Effective oil/water separation continues to be a major challenge in heavy oil (HO) production operations and often involves high capital costs (large, heated vessels) and high operation costs (heat, fouling, upsets, chemicals). Application of new electrostatic dehydration technologies has the potential to have a major impact in reducing these costs. A systematic evaluation of four electrostatic dehydration technologies was performed using lab, bench scale, and pilot scale (40 gallons) testing. Four heavy oils ranging from 8 to 21 API were used. Performance criteria measured were effective emulsion separation rate (vessel throughput), separated oil and brine quality, water droplet size distribution for inlet and outlet emulsions, and comparison with field data (as available) for older electrostatic technologies. Traditional bottle tests were performed for reference. A 2 to 4 fold increase in emulsion treating rate was observed for some of the heavy oils using the newer electrostatic technologies relative to the traditional Alternating Current (AC) method with the same output quality of crude and brine. Relative cost data per barrel of emulsion processed were developed from system cost estimates and throughput data developed in the pilot tests. Treatment with acid to bring the separated brine into a 6 to 6.5 pH range had a very beneficial effect on the oil/water separation for some of the heavy oils with high TAN.
Plugging Channels Technique Without Abandoned Adjacent Layers
Authors: Pei X. , Li Q. , Liu Y. , Zhang S. , Ren S. , Li Q. , Cheng M.
Published: December 2007

This paper analyses the reasons that lead to channeling of the oil and water wells in the Daqing Oilfield. Considering the developed layers' adjustments in the future, a new kind of chemical plugging technique is introduced to shut off the channels without abandoned adjacent layers. To realize the aim of both protecting the adjacent layers and plugging channels, the following steps are usually adopted. First, the channeling intervals should be perforated by a special perforating gun. Second, circulating the channels by a high velocity flush to make sure the agent can be squeezed into it easily. Finally, run the plugging string that carries the agent to the desired depth, increase the pressure to squeeze the agent into the channel, and then waiting for the solidification. Up to now, 12 wells have been treated by this technique. The channeling intervals' thickness is between 1.97 and 38.7 feet. The plugged channels can resist 2175.5psi pressure and the treatments' success ratio was 100%. Applications and excellent results proved that the technique can mitigate contradictions between different layers in the water-flood and polymer-flood area, and it can realize the goal of separate zone injection or separate zone oil production in the Daqing Oilfield.
Application and Study of Fine-Silty Sand Control Technique Using Fiber-Complex High-Pressure Pack in Sebei Gas Reservoir
Authors: Zhou F. , Zong Y. , Liu Y. , Yang X. , Xiong C. , Zhang S. , Sun L. , Wang J. , Li J. , Guang Z.
Published: December 2007

Sebei Gas Field in Qinghai is the fourth largest gas field in China. The reservoirs here are of unconsolidated Quaternary siltstones and pelitic siltstones, alternating gas and water layers and with serious sand production. The grain size of the sands is very fine, so it is very difficult to realize sand control, a cosmopolitan puzzle. We have succeeded in applying a series of techniques of comprehensive sand control with fiber-complex high-pressure packing but without any screen pipe. The technology includes the reservoir pretreatment, the fiber- complex technique and the high pressure packing. As for the reservoir pretreatment, the soft fibers, of which the branched chains are with positive electrical charges, are used to adsorb the fine silty sand particles to form big aggregations for sand stabilization. As for the fiber-complex technique, the 3-dimensional reticular fiber and resin-coated sand complex are adopted for sand retention. As for the high pressure packing, the formation is not fractured while the fiber composites are packed to form screen pipe-like barrier around the cement sheath to perform sand control without any screen pipe used, eliminate any damage to the near wellbore zone and increase the gas bleeding area. This technique can achieve the dual purpose of sand control and production stimulation. This technique system had been applied in Well Se 7-1-4 in Sebei Gas Field with remarkable results achieved. After such sand control treatment, the output without sand production increased on average to 2.1 times of the output before. This paper presents mainly the relevant theory, experimental study, operation design and field application of the fine silty sand control technique using the fiber-complex high-pressure packing without any screen pipe.
Steam and Solvent Coinjection Test: Fluid Property Characterization
Authors: King R. W. , Zhao L. , Huang H. , McFarlane R. A. , Gao J.
Published: December 2007

As part of a study of steam and solvent co-injection processes for MacKay River reservoir, a number of fluid properties of MacKay River bitumen-solvent mixtures were measured for three candidate diluents (referred to as Solvents 1, 2 and 3) at conditions relevant to the co-injection process under consideration. They include viscosities of bitumen-solvent mixtures for Solvent 1 and 2, densities of bitumen-Solvent 2 mixtures of different solvent content and liquid-vapor phase behaviour of the bitumen-Solvent 2-water mixture at a given mixing ratio.

The results showed that the effectiveness of solvent-dilution on oil viscosity became less prominent as temperature increased. The differences among the diluents in lowering the viscosity of MacKay River bitumen were insignificant. At elevated temperatures and above the solvent saturation pressures, increasing solvent loading in the bitumen-Solvent 2 mixture from 10.7 vol% to 19.5 vol% reduced the density of the mixture by only 3 - 5%. At 1750 kPag, the bitumen-Solvent 2-water fluid mixture containing 5.8wt% of solvent and 58wt% of water remained as two liquid phases at temperature up to 165 °C. The mixture formed a three-phase system (one vapor phase and two liquid phases) at 195 °C, with only 6.8wt% of the solvent dissolved into the oil. Small quantities of C10+ components from the bitumen were also detected in vapor phase.

Mixture viscosities were calculated and fitted to a linear-logarithmic mixing rule. A good match with the measured viscosity was achieved at all temperatures below the bubble point of the mixture. K-values of the solvent pseudocomponents were determined using HYSYS and fitted to the correlation to estimate K-value as a function of temperature and pressure.
Case Study of Ultralightweight Slurry Design Providing the Required Properties for Zonal Isolation in Devonian and Mississippian Central Appalachian Reservoirs
Authors: Kulakofsky D. , Snyder S. , Smith R. , Mork K. , Coors D.
Published: December 2007

As the global demand for energy increases, operators are being forced to drill in increasingly challenging environments. In the northeastern United States, that often means exploring unconventional reservoirs such as the Devonian Shale or lower-pressured sandstone reservoirs such as the Big Injun or Berea sands (and drilling through the associated Sunbury Shale). Economic limitations in these areas often require operators to attempt single-stage production cement jobs with associated fills of 3,000 ft or more. Achieving zonal isolation above these low-pressure zones requires low-density cements that are pushing the limits of current cementing technology. If the cement is made light enough to circulate, but cannot withstand the stress of fracturing or other downhole conditions, the initial seal will only be temporary. If cement cannot be successfully circulated or fails to function shortly after placement, this can have a great impact on drilling costs usually designed with very tight economic constraints and can cause delays in production delivery because of required remedial work. Most of these wells require stimulation treatments to become economical producers. If zonal isolation is not initially achieved, remedial work may not be enough to effectively isolate the downhole formations, resulting in a complete loss of the well or zones within the well. Historically, lightweight slurries have been applied in these reservoirs in an attempt to successfully achieve zonal isolation in both single- and multiple-stage cement jobs; however, previous cement solutions were found to be lacking in one way or another. Problems ranged from price to poor bonding results, poor zonal isolation, or more typically designed cement fills not being attained.

As cementing solutions become more advanced in technology, the associated costs often increase. When choosing a cementing solution, the operator should balance price with the potential well productivity and the cost of using a cheaper solution. In this case study, we examine various examples where an effectively priced, high-quality, low-density cement was used to overcome numerous cement challenges, delivering zonal isolation that can allow effective post-cementing stimulation treatments that result in a positive return on investment (ROI).
Feasibility Study of Autoignition Process in Heavy-Oil Reservoirs
Authors: Razaghi S. , Kharrat R. , Price D. , Vossoughi S. , Rashtchian D.
Published: December 2007

Heavy oil is an important part of the energy resource in the world. With today's increasing demand for energy resources, heavy oil recovery is under great attention. Heavy oil deposits in Middle East are in fractured carbonate-type reservoirs that have not been studied in the literature.

One of the important factors in the feasibility of in situ combustion (ISC) on a heavy oil reservoir to sustain fireflood is the auto-ignition temperature under reservoir conditions.

In this study, the kinetic model of different heavy oil samples from South West Iran mixed with silica sand or crushed carbonate rock and clay were studied using Thermogravimetric Analyzer (TGA) and Differential Scanning Calorimeter (DSC) techniques. The reactions were carried using air enriched with different percentages of oxygen.

Two sets of experiments for the combustion of crude oil samples were carried out by TGA equipment for the determination of auto-ignition temperature. In the first, the system was operated non-isothermally with a linear temperature rise 10°C/min; while in the second the reaction was conducted isothermally at different temperatures. In both kinds of experiments the CO, CO2, hexane and propane in the exhaust gases from the TGA, were measured by an Infrared Analyzer (IR).

Based on the TGA runs performed, it is concluded that auto ignition was related to the percentage of enriched air for both the silica sand and carbonate rock in the presence of clay. In addition, as expected in DSC run under non-isothermal Low Temperature Combustion (LTC) and High Temperature Combustion (HTC) reactions clearly reveal exothermic peaks.
A Successful Case Study on Development of a Giant, Highly Fractured Carbonate Heavy-Oil Reservoir in Iran
Authors: Tabibi M. , Mirkalaei S. M. Mousavi
Published: December 2007

The increasing demand for energy in the world and the current status of the oil price are two important issues that drive the industry to re-look the unconventional sources witch can be form of heavy/ extra-heavy black oil and/or exist in deep, over pressured fractures carbonate source rocks. Exploration and production from these kinds of reservoirs, in the past, have not been economically feasible. In this communication, a successful case study on a heavy/extra-heavy oil field is presented and the techniques and challenges behind the exploration and production from highly fractured carbonate Bangestan reservoirs are discussed. The field is a giant structure located in the South West Iran and in the coast of Persian Gulf. It's a symmetrical anticline with 90 Km length and 16 Km width in the surface with about 3.6 billions barrels of initial oil in place and 10-16° API heavy oil. The pressure is 1408 psi at 1119 mdd (measured drill depth) and heavy oil didn't naturally flow to the surface. Exploration of the field carried out for evaluation of gas reservoirs in 1959 and a total of 5 wells have been drilled on this structure, wells number 6 and 7 were drilled in 1984 & 1985 for heavy oil evaluation in shallower formation. A 3D seismic and Side View Seismic Location (SVSL) carried out on this field. The swabbing operation then was performed for one well to identify property of rock and fluid in order to design pilot surface facility. The challenges and techniques employed on this field development including geological study, drilling operation, reservoir characterization and various techniques of production summarized in this paper and optimized production method to lifting this heavy oil to surface is described.
Heavy-Oil Uncertainties Facing Operators in the North Sea
Authors: Morton K. L. , Osman M. S. , Kew S. A.
Published: December 2007

Rising oil price and demand has led to increased effort to develop reservoirs in the North Sea that were previously considered uneconomical by major operators. The recent DTI ‘Promote’ licensing initiative has encouraged smaller oil companies to apply for exploration/appraisal acreage on a limited financial commitment basis for two years before initiating a more traditional work program.

Companies using this option to develop heavy oil reservoirs in the North Sea, many of which were discovered in the 70's, face a number of uncertainties traditionally associated with heavy oil. These include the determination of density and live oil viscosity at reservoir temperature where no clear correlation exists and the determination of reservoir properties from a limited range of historical data. In the offshore environment heavy oil developments are further complicated by the high front-end costs, limited reservoir size and uncertainty in geology and productivity. Only four of the heavy oil fields discoveries on the UK Continental Shelf (UKCS) have reached development and we review these fields to illustrate the challenges.

Many of the reservoir and fluid uncertainties can be addressed with modern logging and analysis methods and recommendations for data gathering campaigns in these environments are provided. The technological challenges of an offshore heavy oil development can be met with advances in sand control, ESP technology and EOR techniques. Combined together these solutions provide more accurate production forecasts, which help the economics of developing the resource to be better understood.

The proposed appraisal and development of a heavy oil field situated in Block 9/3b is used as a case study to highlight the challenges faced by operators in the development of heavy oil fields in the North Sea. Re-evaluation of historical data was used to develop a range of production forecasts that fully capture the potential and risk of the development.
Uncertainty Assessment Using Experimental Design and Risk Analysis Techniques, Applied to Offshore Heavy-Oil Recovery
Authors: Prada J. W. V. , Cunha J. C. , Cunha L. B.
Published: December 2007

The increasing complexity in the development of heavy oil fields is directly associated with the uncertainties in the fluid and reservoir characterization, particularly, in offshore scenarios where difficulties for well testing and fluid and core sampling are present. A probabilistic analysis, instead of a deterministic one is the natural way to face these expected uncertainties. The approach proposed in this work uses experimental design techniques to determine the parameters that have large contribution into the Net Present Value (NPV) of the prospect being analyzed. In the example presented NPV is estimated based on the accumulated oil production response of a flow simulator over a period of 30 years. An uncertainty analysis was done using information about the probabilities of the uncertain parameters. The decision tree technique was used to map all possible outcomes and then to estimate the Expected Monetary Value. A program was written to manage the input/output files of a commercial black-oil reservoir simulator in order to run a total of 1,728 simulations and estimate the NPV for each one of those parameter combinations. In a second analysis, the uncertainty density distribution was derived based on the histogram of the NPV results, assuming that the values of the uncertain parameters cover the entire range of variability.

This procedure was applied to a synthetic case in which the uncertain parameters selected were: porosity, absolute and relative permeability, area of accumulation and exploitation scheme (horizontal or vertical wells).
Wellbore Hydraulics in a SAGD Well Pair
Authors: Das S.
Published: December 2007

In SAGD process a pair of horizontal wells is drilled at the base of a heavy oil and bitumen reservoir, vertically one above the other. Steam is injected into the upper well and the heated and mobilized bitumen drains to the bottom producer and is withdrawn either by natural lift or artificial lift. Uniform distribution of steam along the entire length of the well bore is very important for the uniform growth of the steam chamber. This is very important to make the entire length of the well productive.

Pressure drop along the length of the injector and producer may cause steam break through in one segment and build up of liquid level between the wells. Generally steam is injected at the heel and the toe of the well and is distributed along the entire length primarily through slotted liner. It is expected that this will provide a higher quality steam at the toe end of the well. However, with out proper design the counter current heat transfer between the two streams may result in delivering a poor quality to the toe. In the producer it is necessary to withdraw fluid from the toe and heel. In a concentric design this may cause serious lifting problem if the tubulars are not designed properly and the split between the streams is not right. This paper presents the issues related to SAGD well bore design.
Ranking Oil Viscosity in Heavy-Oil Reservoirs
Authors: Seccombe J. , Bonnie R. J. M. , Smith M. , Akkurt R.
Published: December 2007

The Milne Point field in Alaska produces from the Kuparuk, Schrader, and Ugnu formations. The Kuparuk formation contains light oil, while the Schrader and Ugnu contain heavy oil. The ranges of viscosities are 200 to 10,000 cp in the Ugnu, 20 – 200 cp in the Schrader, and about 3 cp in the Kuparuk.

Over 200 wells have been completed in the Kuparuk and Schrader formations at Milne Point. The Ugnu contains the largest oil in place in the field; however, it has not been developed yet due to the high oil viscosities. To date, only one well has been completed in the Ugnu.

BP is engaged in new studies to find a way to make the Ugnu commercial. This paper discusses an attempt to identify lower-viscosity "sweet spots" within the Ugnu using nuclear magnetic resonance (NMR) measurements.

In 2004, full suites of logging while drilling (LWD) and wireline data were acquired in two newly drilled wells. The primary goal was to compare viscosity predictions from NMR log measurements to geochemical measurements made on fluids extracted from core plugs. For the first time, on a foot-by-foot basis, using LWD NMR, lower viscosity sweet-spots were identified in the viscous Schrader formation and in the very heavy oil in the Ugnu formations.
A New Approach in Modeling Asphaltene Precipitation in Heavy Oil
Authors: Nikookar M. , Pazuki G. H. , Masoudi R.
Published: December 2007

Asphaltene Precipitation is a perennial problem in production of heavy oils. Field condition conducive to precipitation includes normal pressure depletion, acid stimulation, gas-lift operation, and miscible flooding, just to mention a few. To avoid precipitation, it is useful to know the solubility of asphaltene in petroleum liquids as a function of temperature, pressure, and liquid-phase composition. The accurate prediction of phase behavior in multi-component hydrocarbon systems prone to asphaltene precipitation is, therefore, crucial for the economic and safe operation of any petroleum production scenarios.

In this study, the Soave-Redlich- Kwong equation of state (SRK EoS) has been modified based on perturbation theory in order to improve the phase behaviour predictions and develop a more flexible EoS to modeling asphaltene precipitation. The parameters of the new cubic equation of state considered to be reduced temperature and acentric factor dependent. These parameters have been determined using three phase behaviour calculations namely, saturated vapor pressure, vapor volume and saturated liquid density, for 40 pure hydrocarbon and non hydrocarbon compounds with an absolute average deviation percent of 0.814, 2.614 and 5.814, respectively.

Next, applying the newly modified EOS, the Flory-Huggins (FH) model is adjusted to predict asphaltene precipitation more accurately. The adjustable parameter is defined based on solubility parameter of asphaltene in heavy oil. The phase behavior of asphaltene was extended by these modifications and the precipitation of asphaltene is calculated while adding three n-alkenes solvents. The newly developed model predictions for amount of asphaltene precipitation have been compared with Flory-Huggins model as well as available literature data, showing the robustness and reliability of the new approach.
Successful Application of Viscoelastic Fluid Technology to Stimulate a Gas Storage Reservoir
Authors: Fry L. , Stegent N. , Amos J. , Martin J. , Silber R. , Young U.
Published: December 2007

Columbia Gas Transmission operates two groups of natural-gas storage fields approximately 50 miles northeast of Columbus, Ohio. The Silurian-age Clinton sandstone formation in both fields varies significantly in thickness and reservoir quality. Although the gross Clinton interval is fairly uniform, it can include one to three separate sand members.

Reduction in storage-well performance over time dictates the need to periodically stimulate, or even re-stimulate the wells. Fracture stimulation is often required to restore well performance. The objective of the hydraulic fracturing treatments in these wells is to obtain a short, highly conductive propped fracture past the damaged area. Fracturing models are used to determine the optimum tip-screenout treatment design based on individual well characteristics.

Several fracturing fluids have been used in the attempt to achieve the optimum fracturing treatment. Previously, the best results were seen with borate-crosslinked fluids using nitrogen assist. With recent advances in fracturing-fluid technology, conventional borate-crosslinked fluids can be replaced with high-performance viscoelastic fluids, which reduce fluid damage to the proppant pack and formation. The viscoelastic fluid has excellent proppant-transport properties and predictable break times.

Three wells, two in Group I and one in Group II, were selected as candidates for fracturing with the viscoelastic fracturing fluid. Fracturing models were used to design a treatment that would result in similar fracture geometry as the borate-crosslinked fluids. This resulted in up to 40% reductions in total fluid requirements and up to 65% reductions in pad fluid volumes. All three wells were fracture-treated with the designs obtained from the fracture models. Fluid volumes recovered, flowing pressures, and choke size were all recorded during flowback and compared to values from offset wells.

This paper details the properties of the viscoelastic fracturing fluid, fracture designs, and post-fracture results of the wells stimulated with the viscoelastic fluid.
Matrix Shrinkage and Swelling Effects on Economics of Enhanced Coalbed Methane Production and CO2 Sequestration in Coal
Authors: Gorucu F. B. , Jikich S. A. , Bromhal G. S. , Sams W. N. , Ertekin T. , Smith D. H.
Published: December 2007

Increases in CO2 levels in the atmosphere and their contributions to global climate change have been a major concern. It has been shown that CO2 injection can enhance the methane recovery from coal. Accordingly, sequestration costs can be partially offset by the value added product. Indeed, coal seam sequestration may be profitable, particularly with the introduction of incentives for CO2 sequestration. Hence, carbon dioxide sequestration in unmineable coals is a very attractive option, not only for environmental reasons, but also for possible economic benefits.

Darcy flow through cleats is an important transport mechanism in coal. Cleat compression and permeability changes due to gas sorption desorption, changes of effective stress, and matrix swelling and shrinkage introduce a high level of complexity into the feasibility of a coal sequestration project. The economic effects of carbon dioxide-induced swelling on permeabilities and injectivities has received little (if any) detailed attention.

Carbon dioxide and methane have different swelling effects on coal. In this work, the Palmer-Mansoori model for coal shrinkage and permeability increases during primary methane production was re-written to also account for coal swelling caused by carbon dioxide sorption. The generalized model was added to PSU-COALCOMP, a dual porosity reservoir simulator for primary and enhanced coalbed methane production. A standard five-spot of vertical wells and representative coal properties for Appalachian coals were used.1 Simulations and sensitivity analyses were performed with the modified simulator for nine different parameters, including coal seam and operational parameters and economic criteria. The coal properties and operating parameters that were varied included Young's modulus, Poisson's ratio, the cleat porosity, and the injection pressure. The economic variables included CH4 price, CO2 cost, CO2 credit, water disposal cost, and interest rate. Net present value analyses of the simulation results included profits due to methane production, and potential incentives for CO2 sequestered. This work shows that for some coal-property values, the compressibility and cleat porosity of coal may be more important than more purely economic criteria.
Testing Cement Static Tensile Behavior Under Downhole Conditions
Authors: Dillenbeck R. L. , GoBoncan V. , Rogers M. J.
Published: December 2007

Today's analytical models can calculate stresses imposed upon the annular cement sheaths of wells, and it has become apparent that induced stresses can often be tensile in nature. These models often predict the cement failing in tension as well. This understanding has caused the industry to step beyond API tests that only recognize methods for testing cement under compressional loads. Instead, the determination of cement tensile mechanical parameters should be considered as important as cement compressive strength. Unfortunately, with no API guidelines, most oilfield cement tensile behavior testing typically uses ASTM construction concrete test methodology. With oilfield cements, most ASTM tests suffer from various shortcomings. These can be traced to the fact that they are designed primarily to test construction cements that are not usually placed more than a few meters underground. These tests do not incorporate procedures to replicate the curing of the cement in downhole environments, and do not conduct the actual static tensile testing under conditions similar to those occurring in oil and gas wells. When oilfield cements are prepared and cured using API procedure in HTHP curing chambers, they must still be subjected to significant induced stresses as cooling and de-pressurization back to ambient conditions occur before they can be subjected to ASTM tests. Samples prepared and tested in such a manner may undergo sufficiently induced stress to exhibit physical signs of initial mechanical failure, prior to even being placed in ASTM testing fixtures.

To produce cement tensile behavior data that is more reflective of actual downhole performance, the authors developed an automated, microprocessor controlled testing device that cures and mechanically tests the cement under simulated downhole conditions. Once slurry is placed in the testing device, and the temperature and pressure is ramped up to simulate downhole curing conditions, the samples never see ambient conditions again until the conclusion of testing. The microprocessor controls and automated data acquisition unit also allow for the determination of tensile stress-strain relationships, prior to testing the sample to ultimate (mechanical) failure in tension.

In this work, the authors present detailed descriptions of the operational capabilities of the new testing device, along with data developed with the device. Using the tensile data developed under more realistic downhole conditions, induced stress models can now generate even more accurate predictions about fit-for-purpose cement designs for wells of all depths and applications.
Long-Term Gas Storage Deliverability Improvement from Fracturing and Refracturing Treatments Using a Proppant Surface Modification Agent
Authors: Guoynes J. , Kozera G. A. , Shaw J. S. , McCallister J.
Published: December 2007

This paper presents long-term follow-up results from post-fracture and post-refracture deliverability testing for 56 gas storage wells. The wells studied include 32 injection/withdraw (IW) wells hydraulically fractured with surface modification agent (SMA) applied to the proppant and 24 IW wells hydraulically fractured without SMA applied to the proppant for sand flowback control.

Deliverability sustainability results previously presented1 will be updated for these treatments from a 6- to a 9-year period. The results will include analysis from deliverability data for SMA-treated and non-SMA-treated wells over six to nine IW cycles. Three wells of the original group of 24 wells previously fractured without SMA were refractured using SMA.

In the original study, a number of wells were fractured without using SMA proppant. These earlier stimulation treatment wells suffered some operational problems and the need for proppant flowback control became apparent. The addition of SMA to fracture treatments reduced operational problems related to produced sand and fracture treatments improved deliverability. The wells that included a SMA now have been through six to seven complete pressure cycles and the long-term effects of sand flowback and well performance can be compared.

The results of this updated study show that SMA injected with the proppant helps reduce operational problems in gas storage fields by reducing proppant flowback. In addition, analysis of SMA fractruring treatments in gas storage wells typically show no detriment to long-term performance. In addition, SMA can improve results from refracturing.
Cold Heavy-Oil Production at Patos-Marinza, Albania
Authors: Weatherill B. D. , Seto A. C. , Gupta S. K. , Çobo L.
Published: December 2007

The Patos-Marinza Heavy Oil Field, located in southern Albania, was discovered in 1928. The reservoir, with oil specific gravity ranging from 0.86 to 1.05 (3 to 33 °API), contains one of the largest onshore oil resources in continental Europe. Primary production commenced in the 1930s and reached a peak rate of over 3,300 m3/d in the late 1950s. By June 2004, over 2,400 wells had been drilled, at an average spacing of about 3.6 hectares, and cumulative oil production amounted to about 19 million m3. However, the expected ultimate oil recovery by primary recovery was only about 6% of the original-oil-in-place (‘OOIP’).

In 1999, foamy oil production was successfully tested in the laboratory for field application at Patos-Marinza. Subsequently, progressive cavity pumps (‘PCP’s) were installed in 12 wells in the northern region of the field completed in the main Driza sands, as a pilot test of Cold Heavy Oil Production (‘CHOP’) technology to improve recovery. In July 2004, an intensive campaign of well reactivations using CHOP technology was initiated under new operatorship.

The performance of the pilot test indicated that foamy oil behavior had been clearly initiated at 5 of the initial test wells as a result of the increased drawdown applied to the reservoir. Oil production rates were increased significantly, by an order of magnitude, between 10 m3/d and 20 m3/d. In addition, sand cuts of between 5% and 20% and foam cuts were reported.

The performance of the wells put on CHOP production since change of operatorship in July 2004, have yielded good results. As of July 2005, the current operator has taken over 76 wells and continues to progressively apply CHOP technology to the field. This paper focuses on the wells that have exhibited clearly defined CHOP performance characteristics and reports the initial results in terms of well production rate responses.