bluuebunny/crossref_metadata_2025 huggingface dataset:
Block Size and Fracture Permeability in Naturally Fractured Reservoirs
Authors: Rivas-Gómez Santiago , Cruz-Hernández Juana , González-Guevara José A. , Pineda-Muñoz Armando
Published: December 2007

During a naturally fractured reservoir simulation process, reservoir engineers use some important properties of the reservoir as the number and width of fractures, block size, fracture permeability and the shape factor. Some times these properties are taken in an independent way, causing waste of simulation time.

In this paper a relation among the mentioned reservoir properties and the well production, based on Darcy's equation is presented. The relation obtained for the total flow rate, that includes the matrix and the fractures contribution, and the number and width of fractures shows that there are different sets of values that give the same production, but they are dependent each other. This method contributes to define by means of the data obtained in production tests, the mentioned parameters, makes them consistent and determines all the values when one of them is known. An application is presented using the data of Cantarell field, the largest one fractured reservoir in Mexico. Different combinations of parameters are shown, the ranges for the reservoir properties are discussed and also the way to define them.
Seismic fracture detection at a Middle East offshore carbonate field
Authors: Holmes Gordon M. , Thomsen Leon
Published: December 2007

In 2001, a wide-azimuth 2C/3D OBS survey was acquired over an offshore carbonate field in the Middle East, and processed with techniques specifically designed to preserve and extract the azimuthal effects in the data. The results showed significant azimuthal anisotropy in amplitude, with apparent azimuthal variation in the P-wave AVO slope of as much as 100% at selected target horizons. The azimuth of the most positive slope was generally NW/SE, in agreement with the regional tectonic trend. The magnitude of the anisotropy varied markedly, with patches of strong anisotropy, with a granularity of 10's to 100's of metres, and a regional trend on the 2km scale. Vertical variation of these patches supports the hypothesis that the effects are due to subsurface anisotropy, rather than acquisition artifacts.
Management of Stress Sensitive Reservoirs Using Two Coupled Stress-Reservoir Simulation Tools: ECL2VIS and ATH2VIS
Authors: Onaisi Atef , Samier Pierre , Koutsabeloulis Nick , Longuemare Pascal
Published: December 2007

The stress state in and around a reservoir can change dramatically due to changes in pore pressure, temperature and water saturation caused by either depletion or water injection. Both depletion and water injection may cause deformation of the rock and alteration of the rock fabric, which in turn gives rise to phenomena such as compaction and subsidence, induced fracturing, opening of natural fractures and fault slip. These mechanical and chemical phenomena continuously affect the reservoir properties, the flow pattern in the reservoir and ultimately the recovery factor. In addition, changes of stress within the reservoir and in the overburden require special consideration in the design of wells to prevent sand production and casing collapse and for later infill drilling.

To capture the link between flow and concomitant depletion and/or injection pressures and in situ stresses at field scale, it is essential to perform coupled reservoir-geomechanical simulations. This paper introduces the ECL2VIS and ATH2VIS tools, which provide a two-way link between the reservoir simulators ECLIPSETM1 and ATHOSTM2 and the geomechanical stress simulator VISAGETM3. The basic versions of these coupled simulators take the pore pressure and temperature increments calculated by the flow simulator and use them in the geomechanical simulator, which calculates corresponding changes in stresses that are used to update the permeability in the flow simulator.

The latest versions of ECL2VIS and ATH2VIS address the issues of compaction drive. These versions will also allow for the modification of the mechanical properties of reservoir rocks due to corresponding changes of water saturation. The compaction-drive algorithm, with or without water weakening effects, forces the pore volume calculated by the flow simulator to be similar if not equal to the pore volume obtained from strain calculations.
The Effect of Wettability on Saturation Functions and Impact on Carbonate Reservoirs in the Middle East
Authors: Masalmeh Shehadeh K.
Published: December 2007

Wettability is an important factor, which affects the flow behavior in oil reservoirs. It has a profound effect on the shape of relative permeability and capillary pressure curves and consequently on oil displacement processes in porous media. This paper presents experimental measurements on core samples where the effect of wettability is investigated on connate water, residual oil, oil and water permeability end points, relative permeability and capillary pressure curves.

The paper summarizes the main findings of few years of data collection on several cores from different carbonate fields in the Middle East, and a comparison with clastic data is made when appropriate.

The data shows very low connate water for most carbonate fields investigated in this study even for low permeability rocks, 1 md. The residual oil saturation after restoring wettability was measured to be less than 10% for both carbonate and sandstone fields. For water-wet samples a residual oil of around 30% is measured. A distinct difference was found in the dependence of residual oil saturation on initial oil saturation for water-wet and mixed-wet cores. For water-wet samples Sor increased almost linearly with Soi, however; for mixed-wet samples Sor was found to be constant for a very wide range of Soi values.

For water-wet samples we often measured high oil relative permeability end point, Kro(Swc)>1.0, and it decreased as the wettability changed to mixed-wet or oil-wet. The water relative permeability end point is low for water-wet samples and increased for mixed-wet or oil-wet samples.

As demonstrated in the field case discussed in this paper, the findings of this study have important implications for field development and hydrocarbon recovery.
Determination of the Effects of Capillary Number, Viscosity Ratio and Wettability on the Capillary Pressure-Saturation Relation Using an Advanced Pore Network Simulator
Authors: Constantinides George N. , Payatakes Alkiviades C.
Published: December 2007

Macroscopic modeling of two-phase flow in porous media is based on the use of appropriate constitutive equations, the most important of which correlates the capillary pressure with the saturation. Several semi-empirical relationships of this type have been proposed in the literature, which include adjustable parameters. In the present work the dependence of capillary pressure on saturation is calculated as a function of the pertinent parameters (capillary number, viscosity ratio, dynamic contact angles, pore structure) using an advanced pore network simulator. The advantage of this approach is the correlation of the mesoscopic properties of the process, such as capillary pressure and saturation, with the main flow mechanisms at pore scale. The calculations involve the actual pore mechanisms and do not use adjustable parameters. The pore medium is modeled as a three-dimensional network of randomly sized unit cells of the constricted-tube type. Solving the problem of forced imbibition and drainage, the time evolution of the capillary pressure is calculated as a function of the saturation and the system parameters.

The capillary number, the viscosity ratio and the wettability affect the capillary pressure-saturation relation strongly and their effects should not be neglected. We find that the shape of the capillary pressure-saturation curve depends strongly on the step increase of the capillary number. The capillary pressure is an increasing function of the viscosity ratio at the initial stages of displacement and a decreasing function of the viscosity ratio at the final stages. The effects of wettability are quite complex and are explained in the full text. The results are correlated with the flow mechanisms at the pore scale (mechanisms of oil disconnection, action of wetting films flowing through pore wall microroughness, distribution of oil in the porous medium, etc.).
Geological Modeling of a Tight Carbonate Reservoir for Improved Reservoir Management of a Miscible WAG Injection Project, Abu Dhabi, U.A.E.
Authors: Gomes J. S. , Ribeiro M. T. , Fouchard P. , Twombley B. N. , Negahban S. , Al-Baker S.
Published: December 2007

This paper presents the methodologies adopted to model a tight carbonate reservoir located in Abu Dhabi and to better predict its performance (completed with horizontal wells) under a water-alternating-gas (WAG) process. The model is built through integrating geological, geophysical, petrophysical, geomechanical, and geostatistical information.

The large-scale reservoir framework is built by integrating horizontal wells and 3D seismic data. Horizontal well results are used to improve the velocity modeling and depth conversion. The fine scale reservoir zonation is based on lithostratigraphic correlations derived from the porosity and micro-resistivity logs. Stylolitic intervals are used as stratigraphic markers to guide the reservoir zonation. The Porosity model is derived from a high resolution stochastic seismic inversion, and the permeability model is generated using cloud transforms with P-Fields applied by reservoir rock types. High-pressure mercury injection data is used to define reservoir rock types. Lorenz plots have been applied and found to be a useful technique for capturing the heterogeneity of the reservoir and determining the main flow units. Fracture analysis is conducted using cores and image logs (FMI). A geomechanical study is performed to assess the orientation of the horizontal wells in the field. A discussion on the orientation of the horizontal wells with respect to maximum principal stress versus productivity/injectivity is also addressed in this paper. A mechanistic compositional flow model is built to perform sensitivity analyses on various WAG schemes (cycle, ratio, etc). A full field compositional model is subsequently built to evaluate the field performance under various development scenarios. The field is scheduled to come on stream by December of 2005.
Saturation Evaluation in Micritic Reservoirs: Raising to the Challenge
Authors: Mario J. C. , Takezaki Hitoshi , Asakura Shigeaki
Published: December 2007

The micritic limestone reservoir zones offshore Abu Dhabi have consistently challenged formation evaluation specialists. For years, zones exhibiting very low resistivity and interpreted as water-bearing, by standard or even more advanced interpretation schemes, have been shown to produce significant quantity of oil. Production tests and core studies have confirmed this fact.

Previous work has shown that a saturation equation still based on resistivity but using a triple porosity model improved the quality of the formation evaluation in these very challenging conditions. One limitation of this very valuable approach was that, in order to ensure an easy analytical solution to the equation, a fixed relationship was assumed between the saturations in the various porosity types, primarily macro- and meso-porosity. Similarly, a fixed exponent was used in the mixing law, combining the respective conductivities of macro-, meso- and micro-porosity.

In this paper, we demonstrate that these limitations can very easily be lifted through an original approach: the saturations in the three types of porosity are computed sequentially, faithfully following the oil migration reservoir model, which states that oil migrates first in the macro-pores, those pores rapidly becoming oil-wet, then in the meso-pores, the micro-pores remaining primarily water-filled.

In addition, the mixing law attempts to model the fact that meso-porosity appears to create a large divergence from Archie's law, which was not fully accounted for by the earlier models, by allowing for a variable exponent, itself function of pore type.

The split between macro-, meso- and micro-porosity is preferably derived from Nuclear Magnetic Resonance logs, but an alternative approach, that can be used when NMR logs are not available, has also been found to give satisfactory results, provided a reliable permeability log is available, which is in itself a challenge in these difficult formations.

This paper describes in details the equations used to arrive at the solution and shows examples of computation, with comparison to core results and to cased hole saturation obtained from a non Archie approach, in particular from pulsed neutron logs.
Development and Deployment of a "Bullheadable" Chemical System for Selective Water shut off leaving Oil/Gas Production Unharmed
Authors: Morgan J. , Gunn A. , Fitch G. , Frampton H. , Harvey R. , Thrasher D. , Lane R. , McClure R. , Heier K. H. , Kayser C.
Published: December 2007

A low concentration chemical treatment has been developed for pumping into a producer from surface to stop water production without harming hydrocarbon production. Matrix reservoirs are the primary target, though the upper permeability limit is not yet known. Numerical simulation has shown that while such a treatment would not be universal, many viable targets exist. Horizontal wells and multilaterals can make ideal targets, as would many vertical wells in heterogeneous formations and hydraulically fractured wells. Key performance targets were set for these chemical selective water-blocking systems (often called relative permeability modifiers). A dilute, water-dispersed system was favoured as treatment volumes were expected to be large in some cases. Because some of the chemical will enter valued oil/gas zones, the chemical must collapse to allow oil/gas to flow back through treated rock. A mechanism for this is described. To be of wide use, the chemical system should inhibit water production in reservoir rock with matrix permeabilities up to 10 Darcy, and at temperatures up to at least 110 °C. Simulation indicated the minimum degree of water block required for selected targets. However, laboratory tests showed that blocks beyond 99.5% could be slow to clean up to hydrocarbon flow under available drawdown. This gave a performance target range. Well targets should always have appropriate reservoir stratigraphy, but it may not be possible to log the wells pre-treatment to check hydrocarbon/water inflow distribution. Therefore some "high-risk" treatments would fail because of lack of separate oil inflow, or absence of any flow barriers (such as shale) between water and remaining oil. A simple remediation treatment option was therefore required. Also, low toxicity and compatibility with production facilities were seen as non-negotiable properties. We describe the key molecular design parameters derived to give a polymer/crosslinker system with the performance demanded from simulation. Laboratory test results showing the required water/oil block performance and long term stability (at 100 °C) are presented. Field deployment designs including "rule of thumb" treatment volumes are described. The polymer and crosslinker were manufactured at full scale for trial application. Quality assurance tests of this unique "dancing-thin-gel" system are detailed. Results of several full-scale "calibration" field trials are presented. Lab-field correlation appears to be acceptably robust.
TOTALFINAELF Experience and Strategy in Downhole Processing
Authors: Gay Jean-Claude , Minebois Jean-Loup , Lacourie Yves , Lecoffre Yves
Published: December 2007

Water is very often associated to the oil production, for geological reasons, but also because it is the most frequent mean of secondary recovery. However all fields are not comparable in their behaviour. In the best cases water is effectively contributing to the oil sweeping and the bulk of the oil reserves can be produced at low water cuts. In other cases, it can be said that water is inevitable to the oil and huge volumes of high water liquids must be lifted from an early stage to produce the oil.

In some cases, mechanical or chemical water shut off techniques can help to reduce the water production however, depending on the specific conditions, they are not always cost effective, their implementation can be tricky, and their efficiency may be limited in time.

Therefore the operator is often left with the standard solution of upgrading its field and process facilities to cope with the produced water constraints. However, due to the increase difficulties resulting from the drastic new environmental regulations, the operators tend to focus more than before on the produced water associated cost.

A typical offshore field production history and capex and opex breakdown was analysed to highlight the impact of the water on a field economy.

The new interest linked to the emerging technology of downhole separation and re-injection has motivated the testing of a DOWS unit on the well LA-90 in the Lacq Superieur field in France and results of this operation are presented.

Considering the shortcomings in the existing static cyclone technology which is implemented in the down hole separation systems, TFE has undertaken since three years a R&D program based on an innovative concept of rotary cyclone. The base of the theory and its implementation are presented along with the promising preliminary results.
Plant Integrity Management Reviews
Authors: Oliver Michael H.
Published: December 2007

A major concern of companies operating refineries, gas and chemical plants is continued assurance of plant integrity. Plant integrity is loosely defined as assurance that there will be no "loss of containment", that all safeguarding systems act in the desired manner at the proper time and that the equipment is being operated within predefined limits, not necessarily design limits, that are necessary to assure continued operation from one major shutdown to the next. There are two approaches to managing plant integrity, the first being a reactive approach which tends to correct threats to integrity as they occur and the second being a "business process" approach. The business process approach to managing integrity is a proactive way of managing integrity in which failure modes are anticipated and the proper safeguards are put in place to prevent degradation or failure. In most cases, a combination of the two approaches is necessary to bring a plant back to the original level of integrity. The reactive mode is for correcting known problems and then business processes must be implemented in order to prevent future deterioration of plant integrity. Typically, an integrity review for a plant is carried out over 2 – 3 weeks by a multi-discipline team of technical experts well versed in the development and application of business processes

Typical business processes that have been developed for managing integrity include the following: Risk Based Inspection (RBI) which defines the interval between inspection of vessels and piping thus assuring that the more critical pieces of equipment are inspected over shorter intervals and less critical pieces over longer intervals.Defect Elimination, which is a process that captures incidents, determines the root cause with a structured root cause analysis and then based on business premises, establishes the best solution for the problem.Competency Assurance, which assures that personnel who operate and maintain the plant meet minimum standards of competency appropriate for the job they are doing.Integrity Operating Windows, which is a process, associated with RBI that defines the allowable limits of operating variables (not mechanical design limits) for critical equipment such that operation within the limits assures integrity for the interval between inspections.

A thorough understanding of the fundamentals of Risk Management forms the basis of most of these business processes and is therefore also a critical ingredient of modern integrity management.
An Integrated Approach for the Design of Squeeze of Mineral Scale Inhibitors
Authors: Bazin B. , Kohler N. , Broseta D. , Le Gallo Y. , Delaplace P. , Longeron D.
Published: December 2007

Inorganic scaling is the process of mineral scale deposition that may occur in the well tubing, and/or in the near well-bore area of both production or injection wells. Scale formation is usually the result of poor compatibility between the brines injected into the reservoir and the minerals in the formation. It may also be the consequence of abrupt pressure and temperature variations to which production fluids may be submitted between the reservoir and the surface. The precipitation of mineral deposits (carbonates, sulfates …) may create significant permeability impairments due to plugging of pore throats and thus induce large well productivity or injectivity losses. In most cases, precipitation cannot be avoided and preventive treatments are recommended. One of the most efficient treatment consists in squeezing a scale specific inhibitor into the formation.

This paper presents an original integrated methodology aiming at defining the best chemical inhibitor formulation for a given application and at optimizing its implementation into the corresponding reservoir. Both experimental and numerical approaches are used to select the inhibitors, to evaluate their performance at both core and field levels and to define the best strategy for the squeeze process. Laboratory tests include the classical inhibitor selection methods based on jar tests and tube blocking tests but also on more sophisticated testing procedures recently developed. Numerical simulations of the treatment are performed using a in-house reservoir simulator to upscale the squeeze life time of the treatment from laboratory scale to well geometry.
Sour Gas Injection Project
Authors: Miwa Masahiro , Shiozawa Yuji , Saito Yoshiharu , Tarmoom Ihab Othman
Published: December 2007

In close collaboration with Abu Dhabi National Oil Company (ADNOC) and Supreme Petroleum Council (SPC), Abu Dhabi Oil Co., Ltd. (Japan) (ADOC) has been instrumental in introducing, for the first time to the Arabian Gulf region, the challenge of sour and acid gas injection technology. The objective of the Sour Gas Injection Project is to capture excess daily flared gases at ADOC's offshore operation site, which in turn reduces toxic emissions into the atmosphere, and re-inject it into oil reservoirs at an injection pressure as high as 6, 000 psig for enhanced oil recovery. This paper discusses ADOC's historical mode of operations, adopted process description, lessons learnt during the project implementation and commissioning, and the project impact on the local environment and oil recovery.
Solar Dew® – The Prospect of Fresh Water in the Desert
Authors: Verbeek Paul , Straccia Joe , Zwijnenberg Harmen , Potter Marinus , Beek Arno ter
Published: December 2007

Solar Dew® technology is a novel way to purify water produced from oil fields, contaminated with traces of oil, metals, noxious gases and potentially high levels of mineral salts. Water purification is enabled by non-porous membrane distillation combined with renewable solar energy. Access to fresh water in the desert would have far reaching benefits, i.e., it provides sustainable development opportunities for local communities whilst it provides the producer with more diverse options for water re-use as an alternative to disposing water into deep aquifers as a waste.

The paper describes qualification trials of the Solar Dew system using water produced from an oil field in south Oman. Trials, executed in 2001 at small scale in the laboratory and in the field, demonstrated that the performance in year-round weather conditions consistently met targets set for quantity and quality of fresh water. Scale-up trials in 2002 aim to demonstrate that a hectare flowing system can be run, that polymer membrane materials are durable and that the system can compete with alternative means of water purification. Trial results indicate that up to 90% of the volume may be extracted as pure water, meeting international quality standards, at a rate of over 50m³ per hectare per day.
Introduction of Oil Spill Crisis Management System
Authors: Okayasu Kunio , Sato Akihiko , Sasaki Chikara , Al Minhali Ahmed A. , Bensahraoui Mohamed , Radhwan Ali M. , Keogh Michael
Published: December 2007

A crisis response exercise, "EXERCISE GHAZAL", was conducted in 1999 to give the ADNOC Crisis Management Team (CMT) practice in dealing with a realistic oil spill scenario in real time. The debriefing of this exercise clearly recognized the importance of sharing information through proper means of communication. Sharing information is essential for the Emergency Response Center (ERC) to effectively manage emergencies. It was also recognized that a useful computerized tool to assist in the management of an emergency was not available in Abu Dhabi. As ADNOC intends to introduce a common emergency management system to its Group of Companies, JODCO/CRC have been working with ADMA-OPCO to develop a PC based system called "InfoBook".
How to Etimate the Maximum Achievable Drilling Rate without Jeopardizing Safety
Authors: Akgun Ferda
Published: December 2007

Recorded drilling times may show significant variations from well to well even for the same total depth in the same field. Apart from the formation characteristics, engineers' technical ability plays an important role in determining drilling time.

A drilling performance is usually compared with respect to the performances of previously drilled wells. This approach has two major drawbacks. One, in newly developed fields, there may not be sufficient number of drilled wells to make a healthy comparison. Two, past drilling practices may not represent good engineering practices.

In this paper, a different approach is introduced in assessing drilling performance. The new approach suggests a comparison of drilling performance with respect to what is called ‘technical limit of drilling rate’, a maximum achievable drilling rate without risking drilling safety.
Using Statistics To Evaluate A History Match
Authors: Uldrich David , Matar Saad , Miller Hugh
Published: December 2007

Three methods are proposed for quickly evaluating the history match of a numerical simulation to actual reservoir performance. All of the methods rely on computing a set of deviation values, each of which is defined to be a calculated simulator result minus the corresponding surveillance measurement value.

For any particular type of surveillance data, such as rates, watercuts, or gas-oil ratios, the deviation values can be grouped by well, by area, or combining all measurements in the database. The first two proposed methods rely on simple graphical presentations of each group of deviation values to show how well the simulation results match the surveillance data. Plotting together the results from more than one simulation run allows a quick comparison of the match for each run, which is useful during the history match process.

The third method converts each deviation value to a quantity called Match Factor, which is a relative measure of the confidence that the simulator actually reproduced the particular reservoir performance at the time the surveillance measurement was made. Weighted-average Match Factors can reveal the degree of match by well, by area, and by data type.

These techniques are especially valuable when matching reservoirs with a large volume of surveillance data. They can help focus the history matching process by identifying areas less well matched. They can identify when the history matching process is not significantly improving the match and can stop.
Modeling of Simultaneous Proppant Fracture Treatments in the Fruitland Coal and Pictured Cliffs Formations in the San Juan Basin
Authors: Bazan Lucas W. , Larkin Sam D. , Jacot R. Henry , Meyer Bruce R.
Published: December 2007

Limited entry design techniques have proven successful for the simultaneous fracture stimulation of the Fruitland Coal and the Pictured Cliffs sandstone in the T28N-R7W Federal Unit of the San Juan basin, Rio Arriba County, New Mexico1. Optimization of this completion technique is dependent upon determining and placing the required effective propped fracture length in the coal and sandstone formations.

This manuscript addresses utilizing limited entry techniques and a 3D fracture model. The model is then used to design N2 foam proppant fracture treatments in the coal and sandstone formations. This completion methodology allows reserves to be recovered from the Fruitland Coal at a significant cost reduction.

With the different mechanical and reservoir properties of the two formation types, created fracture geometry will vary in each formation. Methods used to model these varied fracture geometries are discussed. Net pressure and production data analysis provide estimates for the effective propped fracture lengths in each formation.

Radioactive tracer and production logs are presented as supporting evidence to validate the well completion design, the fracture modeling inputs and the stimulation of both formations simultaneously.

Using this fracture modeling technology leads to increased reserve recovery and cost effective proppant fracture treatments.
Case History: Horizontal Well SAGD Technology is Successfully Applied to Produce Oil at LAK Ranch in Newcastle Wyoming
Authors: Grills Tracy L , Vandal Bryan , Hallum Frank , Trost Paul
Published: December 2007

Several attempts have been made in the past to apply enhanced oil recovery ("EOR") techniques to the Newcastle Sandstone formation at LAK Ranch in Eastern Wyoming. Solvent flood, steam stimulation, and chemical flooding have all been tried without significant success. Utilizing horizontal wells and the Steam Assisted Gravity Drainage ("SAGD") process, Derek Resources was able to successfully produce in excess of 5000 barrels of oil during two short (three-month) sessions of initial pilot production testing.

The Newcastle formation is an alluvial channel with a pay thickness of 25 to 100 feet, averaging 25 to 30 feet. It differs from conventional formations in that formation beds dip at up to 20 to 25 degrees. To further complicate drilling, the reservoir forms a synclinal basin, resulting in constantly changing bedding orientation; and a series of inter-bedded shale stringers make drilling horizontally along strike a challenging process.

The initial SAGD pilot consisted of a single well pair drilled for Derek Resources by Sperry Sun Drilling Services in July of 2000.

This paper will discuss the application of the SAGD process in a non-traditional reservoir, requiring non-traditional well pair geometry. The paper will cover the background to LAK Ranch. This paper will review planning phases for the project, drilling problems encountered, drilling results, and lessons learned from the drilling operation. Startup problems, production results, lessons learned about a project of this type, and future plans for LAK Ranch will also be discussed.
Project Scenarios for Bitumen Upgrading
Authors: Koppel Paul E. , Mazurek William L. , Harji Abdulla
Published: December 2007

The size of Alberta’s heavy oil resource has been well documented with all the superlatives regarding its size. It is truly enormous with established reserves of 178 billion barrels and potential recoverable reserves of 315 billion barrels. However, the logistics of recovery, upgrading, and transportation to market are daunting.

Even after the challenges of production, utilization of the produced bitumen is far from straightforward. It is too viscous to transport by pipeline and not processable by the vast majority of existing refineries. Thus in order to develop a mass market, the bitumen must be upgraded to a quality that can be processed by the existing North American refinery market.

The intent of this paper is to analyze the factors impacting which method of upgrading to follow and give some illustrative examples.
Novel Cement System for Improved Zonal Isolation in Steam Injection Wells
Authors: Dean Gregory D. , Torres Ricardo Sadovski
Published: December 2007

Over the past several years much interest has been generated in the industry of late in the development of ductile cements, exhibiting high values of tensile and flexural strength. There has been a great deal of field information suggesting that hydraulic isolation from cement is not what it should be or is believed to be. In other words many cement jobs are failing. Conventional cement systems used in oil wells exhibit high compressive strengths, yet are limited in tensile and flexural strength development. Recent field experience and research has shown that in the majority of cases, the mechanism of cement sheath failure is radial tensile cracking, causing a loss of hydraulic isolation.

Flexible cements are more able to withstand the tensile forces generated by fluctuations in downhole pressure and temperature caused by drilling, production and workover operations. Also affecting the cement seal are factors such as hydraulic fracturing treatments, high drawdown pressures, steam injection, and subsequent drilling operations.

This paper reviews the application of a flexible cement designed to address problems with loss of hydraulic isolation encountered in steam injection wells. The paper also reviews the basic principles for estimating the cement tensile strength requirement and describes the process used in selecting the final cement slurry formulation, including the use of a mathematical simulator. Also described is the introduction of a novel mineral fiber, which imparts higher tensile strength to the set cement and results in slurry that is better able to withstand the high temperatures induced by steam injection operations. The new flexible cement is also able to provide the required characteristics at lower slurry densities. A summary is presented of the results of the first 4 wells cemented with this technique in the Mossoró area of Northern Brazil.
Comparison of CSS and SAGD Performance in the Clearwater Formation at Cold Lake
Authors: Scott George R.
Published: December 2007

Data are available for four SAGD projects and two CSS projects operating in the Clearwater formation at Cold Lake. This paper uses these data to compare the energy efficiency and recovery performance of SAGD and CSS.

For the conditions outlined in this paper, field data demonstrate that: Bitumen recovery using SAGD is generally uneconomic in the Clearwater formation.Bitumen recovery using CSS in the Clearwater formation:Produces as much as 50% or more bitumen/m3 external gas consumed than SAGD; andWill result in significantly higher overall bitumen recoveries (as a percentage of OBIP) than SAGD.

These observations are consistent with industry experience in non-Clearwater SAGD and CSS operations.

In addition, operating and design data for commercial SAGD and CSS projects is used to demonstrate that: Due to differences in steam quality, SOR is not an appropriate indicator of energy efficiency. Energy efficiency comparisons are more appropriately based on the quantity of external gas required to produce 1-m3 of bitumen.To convert SOR data to an external gas requirement, the following conversion factors are proposed: 1-m3 wet (80% quality) steam requires approximately 60-m3 gas.1-m3 dry (100% quality) steam requires approximately 75-m3 gas.The use of project specific EBIP, versus OBIP, in calculating recovery makes meaningful comparisons difficult.
Conditional Stochastic Moment Equations for Uncertainty Analysis of Flow in Heterogeneous Reservoirs
Authors: Li L. , Tchelepi H. A.
Published: December 2007

We consider permeability as a random space function defined by its mean and covariance. The stochastic nature of the permeability description leads to uncertainty in flow-related quantities such as pressure, saturation and production rate. We extended our statistical moment equation (SME) approach to accommodate conditioning. The conditional stochastic moment equations (CSME) framework is a direct approach for quantifying the uncertainty in flow performance due to uncertainty in the reservoir description. It is quite different from Monte Carlo Simulation (MCS). In MCS, the performance uncertainty is obtained through a statistical post-processing of flow simulations, one for each of a large number of equiprobable realizations of the reservoir description. We developed a CSME computational tool for flow in heterogeneous domains. We employ an approach analogous to the deterministic streamline-based method in order to solve the equations that govern the first (mean) and second (variance and covariance) moments of interest. This numerical CSME tool allows for quantifying the value of existing and future information, and that helps evaluate existing projects and steer future development plans. We present several examples that demonstrate how to choose the best sampling locations to obtain maximum reduction in prediction uncertainty. We compare our results with high-resolution MCS.
A Strategy for Rapid Quantification of Uncertainty in Reservoir Performance Prediction
Authors: Subbey Sam , Christie Mike , Sambridge Malcolm
Published: December 2007

This paper will describe a strategy for rapid quantification of uncertainty in reservoir performance prediction. The strategy is based on a combination of streamline and conventional finite difference simulators.

Our uncertainty framework uses the Neighbourhood Approximation algorithm to generate an ensemble of history match models, and has been described previously. A speedup in generating the misfit surface is essential since effective quantification of uncertainty can require thousands of reservoir model runs.

Our speedup strategy for quantifying uncertainty in performance prediction involves using an approximate streamline simulator to rapidly explore the parameter space to identify good history matching regions, and to generate an approximate misfit surface. We then switch to a conventional, finite difference simulator, and selectively explore the identified parameter space regions.

This paper will show results from a parallel version of the Neighbourhood Approximation algorithm on a Linux cluster, demonstrating the advantages of perfect parallelism. We show how it is possible to sample from the posterior probability distribution both to assess accuracy of the approximate misfit surface, and also to generate automatic history match models.
Accurate Subgrid Models for Two-Phase Flow in Heterogeneous Reservoirs
Authors: Efendiev Yalchin R. , Durlofsky Louis J.
Published: December 2007

Subgrid effects can have a strong influence on flow and transport in oil reservoirs. In this work a new model for the representation of subgrid terms is introduced and applied to two-phase reservoir flows. The model entails a generalized convection-diffusion treatment of the saturation equation as well as an extended representation for total mobility in the pressure equation. Motivation for the form of the model is provided through a consideration of volume averaging and homogenization results. The numerical computation of the subgrid terms and the implementation of the overall method are described. The accuracy of the new subgrid representation is compared to that of coarse scale models with no subgrid treatment and to coarse models based onpseudo relative permeabilities. The new model consistently provides more accurate overall coarse scale predictions, relative to reference fine scale results, than the other coarse scale models, particularly in cases when the global boundary conditions vary in time.
Dual Mesh Method in Upscaling
Authors: Audigane Pascal , Blunt Martin J
Published: December 2007

We develop and test a dual mesh approach to upscaling. A fine grid model is divided into coarse blocks, each of which contains many smaller cells. Pressure is computed first on the coarse grid using upscaled average transmissivities. These pressures are then used to compute the pressure at the small scale within each coarse block. In this way an approximation for the pressure is obtained without ever having to solve the full fine-grid problem, saving both CPU time and memory. The velocity is everywhere continuous and used to transport fluids on the fine grid - this step is no different from a conventional finite-difference approach once the pressure field is known.

We develop the method for multi-well two-phase incompressible flow with gravity in three dimensions - the method is an extension of the work of Verdière et al.1,2, and uses ideas developed by Gautier et al.3 in the context of streamline-based simulation. We discuss how this approach can be the platform for a fully decoupled dual mesh approach, where the fine grid transport problem is also decoupled into a series of coarse cell problems, resulting in a rapid but accurate method that can be applied in principle to grids with any number of cells.

We test the approach on two and three-dimensional problems with gravity. One of the test cases is a model from the SPE 10th Comparative Solution Project on upscaling4. The dual mesh method gives results that are very close to the fine grid results, but uses less CPU time and memory. The results are good even when a very coarse mesh is used and the method is more accurate than using standard single-phase upscaling techniques.
Locally Streamline-Pressure-Potential-Based PEBI Grids
Authors: Mlacnik Martin J. , Harrer Andreas W. , Heinemann Zoltan E.
Published: December 2007

Streamline pressure-potential (SPP) grids are a very promising tool for reservoir simulation, allowing to honor the actual path of flow. These grids represent a successful combination of streamline simulation and finite difference methods. One of the major challenges of this technique is that with changing flow conditions the grid needs to be altered over the period of a simulation run.

This paper presents the application of the windowing technique, introduced by Deimbacher and Heinemann1, to locally honor the changing directions of flow by modifying the grid during a simulation run. One or multiple parts of a reservoir model can be represented by windows with the objective to minimize the grid orientation effect and to enhance the CPU performance by locally incorporating time dependent streamline pressure-potential based PEBI grids.

In a first step the fully implicit solution for the full model will be calculated, but the inner blocks of the window, represented by a fine scale Cartesian grid, are solved for pressure only. Saturations and mole fractions will not be updated during this step. The solution of the first step provides the boundary influx for the windows and the pressure distribution that allows to determine the grid points of a streamline – pressure potential grid. Based on this point distribution a new window grid will be constructed using the PEBI algorithm. The new grid will then be solved in a second step, where the window is calculated for the same overall timestep, using the boundary flux determined during the first step.

The paper describes the generation of locally streamline based PEBI grids and presents results obtained from the application of this technique. A small scale example highlights the advantages of the proposed technique to handle the grid orientation effect. A further example demonstrate the application of the technique in full scale simulation models.
Upscaling Fluid-Flow and Geomechanical Properties in Coupled Matrix+Fractures+ Fluids Systems
Authors: Couples G. D. , Lewis H. , Reynolds M. A. , Pickup G. E. , Ma J. , Rouainia M. , Bicanic N. , Pearce C. J.
Published: December 2007

We have developed a coupled simulation approach, HYDRO-DDA, which calculates the fluid flow through, and geomechanical interactions within, a system of matrix blocks plus their bounding fractures. The flow and deformation behaviours of these simple, but realistic, systems do not agree with common "rules-of-thumb". The upscaled properties of these systems can potentially be used within large-cell reservoir simulations, but some of our models show severe non-linearities and bifurcations, suggesting that coupled hydrogeomechanical upscaling requires due consideration of the context.
Coupled Analysis of Geomechanics and Fluid Flow in Reservoir Simulfation
Authors: Samier P. , Onaisi Atef , Fontaine G
Published: December 2007

Generally, in classical reservoir studies, the geomechanical behavior of the porous media is taken into account by the rock compressibility. Inside the reservoir simulator, the rock compressibility is assumed to be constant or to vary with the pressure of the oil phase. It induces some changes in the porosity field.

During the depletion phase or the cold water injection of HP-HT reservoirs, the stress state in and around a reservoir can change dramatically. This process might result in rock movements such as compaction, induced fracturing, enhancement of natural fractures and/or fault activation, which continuously modify the reservoir properties such as the permeabilities and the fault transmissibilities.

Modifications of such parameters strongly affects the flow pattern in the reservoir and ultimately the recovery factor. To capture the link between flow and in situ stresses, it becomes essential to conduct coupled reservoir-geomechanical simulations.

This paper compares the use of 5 types of approach for the reservoir simulations: ▪A classical approach with rock compressibility using only a reservoir simulator,▪A loose coupled approach between a reservoir simulator (finite volumes) and a geomechanical simulator (finite elements). At given user-defined steps, the hydrocarbons pressures calculated by the reservoir simulator are transmitted to the geomechanical tool which computes the actual stresses and feeds back the modifications of the petrophysical properties (porosities and permeabilities) to the reservoir simulator.▪A one way coupling: this approach is a simplification of the loose coupled approach, the modifications are not fed back to the reservoir simulator.▪A simplified approach using permeability and porosity multipliers inside a reservoir simulator. These multipliers are user defined curves and vary with the pressure of the oil phase. This approach uses only a reservoir simulator.▪A fully coupled approach where the structural and the flow unknows (displacement, pressure, saturations) are solved simultaneously.

These approaches are compared for 2 field cases described below.