bluuebunny/crossref_metadata_2025 huggingface dataset:
Technologies Trials of Intelligent Field Implementation in Carmopolis Field
Authors: Silva M. F. , Portella R. C. M. , Izetti R. G. , Campos S. R. V.
Published: December 2007

Carmopolis field, in the Sergipe/Alagoas Basin, located in the northeast of Brazil, is the country largest onshore oil accumulation. The reservoir is very heterogeneous and has an adverse fluid mobility ratio. During the last thirty years, waterflooding has been employed as secondary recovery method. Hence, considering waterflooding optimization as the main drive, Carmopolis field has been chosen by Petrobras as pilot project in its recently created Intelligent Field R&D Program. In the project, a wide range of technology trials is been conducted, including downhole monitoring, downhole flow-control, and artificial lift optimization. All wells in the pilot area use rod pumps and the aim of the project is to automate completely the system including smart well completions and artificial lift automation with a SCADA system, to accomplish a systematic integration of downhole measurements, communication, and control, thus improving reservoir and production management. The present paper, addresses the challenges faced in the implantation phase of the project, and discusses values and benefits in employing these technologies in an onshore mature field.
Decision Making With Uncertainty While Developing Multiple Gas/Condensate Reservoirs
Authors: Kabir C. S. , Gorell S. B. , Portillo M. E. , Cullick A. S.
Published: December 2007

Well-developed methodology exists for handling uncertainty for a single reservoir. However, development of multiple fields presents significant challenge when uncertainty in large number of variables, such as gas-in place and liquid yield, occur in each reservoir. Some of the challenges stem from our need to forecast the system behavior involving a coupled reservoir/wellbore/surface (CRWS) network for the entire spectrum of variables so that facilities can be designed for the range of fluid composition and throughput. Of course, assessing well count and sequencing well drills are some of the important objectives.

This paper describes probabilistic production forecasting with a compositional CRWS network model for nine reservoirs involved in delivering gas supply to a LNG plant in Nigeria. Our main objective was to use an economic indicator to select optimal design of two main pipelines, each transporting 200 and 300 MMscf/D from the two production platforms, located 15- and 5-km, respectively, from the processing platform.

Rate and cumulative profiles showed that sustained deliverability of gas can be realized for about 11 years before the decline occurred in high-permeability reservoirs. In other words, uncertainty in gas-in-place did not surface during the plateau period, only during the decline period lasting another five years, after the first eleven. In contrast, the liquid rates exhibited large uncertainty band throughout, a direct manifestation of the condensate yield issue. The uncertainty band among each of the 12 components aided facilities design. Differences in net present value (NPV) and discounted profitability index (DPI) were used as discriminators for discerning optimal pipe size from the standpoint of project economics.
Diagnostic Pumping Tests to Optimize Fracturing Designs in the Harsh Environment of Western Siberia
Authors: Manrique J. F. , Winkler A. , Guglielmo D. , Pongratz R.
Published: December 2007

Hydraulic proppant fracturing continues to rapidly evolve in western Siberia/Russia and is seen as the most important and effective means to improve oil production from existing, as well as, newly drilled wells.

Fracture treatments in Russia were traditionally small, conservative treatments with small-sized proppants and inefficient fracturing fluids. They were designed with a one-size-fits-all approach to bypass near-wellbore damage rather than provide sustained and optimum productivity. Results were acceptable for the economic models existing at that time. However, the competitive environment, production targets, and financial goals of oil-producing companies today require a change in approach.

Optimization of hydraulic-fracturing treatments soon became a necessity and resulted in a design methodology aimed at improving the production performance rather than simple modification of pumping schedules. Designing for performance required a change in tactics and an optimization mentality to achieve step-change results.1,2

Production analysis suggested radical changes in fluids, breakers, job sizes, types, and tonnage of proppant, etc. In this paper, we discuss and compare the evolution of the stimulation practices and implementation of technology that matched performance to fracture design. We describe some of the steps and practical standards implemented to improve the performance of hydraulically induced fractures.

In particular, we discuss the critical importance of the minifrac diagnostics used intensively and extensively as a powerful diagnostic procedure. The diagnostic procedure became the most useful and practical tool for fracture placement and successful execution of larger fracture treatment designs with larger proppant sizes, perforating strategy, redesign of fracturing treatments on location, and continuous improvement of treatment designs and placement. The paper will examine the different pumping diagnostics performed in western Siberia and some of the reoccurring results observed. It also evaluates the consistency and specific problems encountered working around the traditional completion and operational practices in West Siberia, and best practices for performing a minifrac during extreme cold.
A Fundamental Model for Prediction of Hole Curvature and Build Rates with Steerable Bottomhole Assemblies
Authors: Pastusek P. , Brackin V. , Lutes P.
Published: December 2007

There are four key technical issues to be addressed when drilling directional wells with steerable bits and bottom hole assemblies: maximizing hole quality, addressing tool face control, eliminating bit and assembly vibration, and predicting hole curvature or build rates. Hole quality1 and tool face control2-7 have been covered in several previous SPE papers, as has bit and assembly vibration elimination8-9. This paper covers the recent development of a fundamental model for the prediction of hole curvature based on measured bit response and modeled bottom hole assembly behavior.

Bit side cutting is a nonlinear function of side force, gauge design, rotary speed, rate of penetration, rock strength, and cutter dull state. To characterize the bit's side cutting response, a series of tests are run in a full scale drilling simulator10 under a variety of drilling parameters and sideloads. Axial and lateral bit trajectories are measured and a response curve is generated. The bit side cutting angle measured in the lab, is equivalent to bit tilt calculated on a bottom hole assembly (BHA). Several hundred tests have been run to measure the response of numerous bits. These response curves are then used to relate bit performance to BHA response.

The BHA is modeled with a finite element analysis program over the range of hole curvatures and tool settings which define the operating envelope for the tool. The result of the analysis is a bit side force to bit tilt response surface for the tool over its operating range. The response curve for the bit and the response surface for the BHA are then plotted on the same set of axes. The intersection of the two graphs represents the steady state response of the system and is used to predict the achievable hole curvature of the bit-BHA system. This work shows that bits often selected for rotary steerable systems are more laterally aggressive than required of the BHA to achieve the desired hole curvature.

The model has been verified with full scale field tests. While this work was originally developed for PDC bits and rotary steerable systems, the fundamental model can be applied to all types of bits and drilling systems. It has also been applied to motor and vertical drilling systems with PDC and Impregnated bits.
Service Line Option for Hydrate Management in Single Flowline Tieback
Authors: Patni S. , Davalath J.
Published: December 2007

Many subsea projects worldwide would benefit technically and commercially from using a single flowline solution to replace traditional dual flowlines. However, the combination of a single flowline, downhill flow and high water cut presents several challenges for hydrate management after an unplanned shut down. Depressurization is the most commonly used technique to prevent hydrate blockages. But depressurization at high water cut may not be successful when the geometry of the flowline results in a liquid head in the flowline riser that is higher than the hydrate formation pressure at ambient conditions.

Options were examined for managing hydrates during high-water cut conditions using service lines in the umbilical to replace the functionality offered by a second flowline. The options examined included using the service line for dead oil displacement, continuous gas lift, expansion of trapped gas, mono ethylene glycol (MEG) injection after emergency shutdown (ESD) and bleeding subsea side trapped pressure. This paper will present an overview of each concept with respect to feasibility, cost, operability and risk issues.

The challenges associated with using the service line options were: ■Hydrate management during extended operations■Impact of the service line on subsea tree design■Support required from host facility■Operability and risk issues

The results of a tradeoff analysis were used to select one concept for detail engineering. The benefits of the single flowline system with the selected hydrate management strategy will be illustrated based on the analysis of a deepwater field development design case.
Comparison of Single- and Dual-Array Microseismic Mapping Techniques in the Barnett Shale
Authors: Warpinski N. R. , Kramm R. C , Heinze J. R. , Waltman C. K.
Published: December 2007

This paper shows a comparison of dual-array microseismic maps with single-well maps for horizontal wells in the Barnett shale. Results from two test cases showing gel and water fracturing maps are given and compared with initial production. Dual-array mapping provides for a much larger areal coverage and increased accuracy when accurate bottomhole locations and velocity structure are available, but do have trade-offs that need to be considered.
Interpreting the Depositional Facies of the Upper Gharif Fluvial System Using Oil-Based Mud Images: A Case Study in Central Oman
Authors: Amer A. , Alexander S.
Published: December 2007

During the early stages of developing Oman's A field, water-based mud (WBM) was used to drill all wells. With this mud system the wells suffered borehole stability problems, especially in the friable paleosols (fossil soils) of the Gharif formation. One of the advantages of drilling with WBM was the ability to run high-resolution microresistivity images.

In the second development stage of the field, oil-based mud (OBM) was used in order to reduce the severe borehole washouts. However, the benefits of microresistivity borehole images were lost.

With the development of the oil-based mud imager tool and its deployment in the A field, key geological and petrophysical information is provided for further successful field development.

This paper explains a new methodology for geologically evaluating the complex upper part of the Gharif formation by introducing integrated data from different sources. Using the electrical oil-based mud images integrated with acoustic images, core data and openhole logs, the facies distribution and typing of the Permian Gharif fluvial system are interpreted over the field.

Nine depositional facies were identified using the oil-based mud images: sand channel, heterolithic channel, abandoned channel, splay/chute, debris flow/sand flat, floodplain/swamp, tidal flat/intertidal, marine shales, and shallow marine limestone facies.

The Upper Gharif stratigraphic interval is subdivided into channel belts separated by thick floodplain shales. The paleocurrent analysis based on these subdivisions illustrates that, in the Upper Gharif, the large spectrum of trends observed for some layers is the result of deposition with almost no accommodation space (meandering channel), whereas other layers show clearer trends indicating possible deposition under higher energy (stream channel type). The value of the oil-based images has been its ability to delineate the channel belt trends and sand prediction for infill drilling.

The identification of these facies and their trends is critical for reservoir evaluation and in field development. However, recent infill drilling results in the Upper Gharif show that sand prediction remains the key challenge to successful development.
Design Considerations for Interventionless, Commingled Multizone Selective Sand Control Deepwater Completions
Authors: Burman J. W. , Renfro K. D. , Conrad M. , Parker C. , Turner D. , Franklin B.
Published: December 2007

Reducing operational risk and improving reliability are major drivers in deepwater completion design. Anadarko's Marco Polo Deepwater Project, located in Green Canyon Block 608 in the Gulf of Mexico, is a 4300-foot water depth development presenting unique completion demands. The Marco Polo Field was developed using multiple frac packs in 6 direct vertical access (DVA), dry tree wells from a TLP.

The completion intervals for Marco Polo are stacked pay zones (5 of the 6 wells have 3 perforated intervals) that were frac packed for sand control and productivity. The development plan is for most initially completed intervals to be commingled downhole, and provide future flow control options to maximize ultimate recovery from all zones. The initiation of production from all zones in each well was desired to be interventionless due to the inherent risk of slickline or coiled tubing operations. Finally, all tool hardware designs had to be compatible with frac packing operations.

This paper will detail the design criteria established for zonal isolation and fluid loss control for the project, testing protocols for the equipment, quality assurance in manufacturing and assembly, contingency plans for the operations and initial results.
Splines as an Optimization Tool in Petroleum Engineering
Authors: Archer R. , Zakeri G. , Vaudrey T.
Published: December 2007

Planning well placements and assisted history matching are examples of some of the difficult optimization problems that occur in petroleum engineering. In both problems objective function evaluations are computationally expensive because they involve forward simulations using reservoir simulators. When gradient based methods are applied to these problems derivatives of the objective function with respect to the parameters (i.e. well location or reservoir properties) are required. The simplest way to calculate these derivatives is by perturbation, which requires further expensive simulation runs. More mathematically complex methods can also be used but these can be difficult to implement.

Response surfaces are used to extract the most value from simulation runs that are made. Prior work has used kriging and least-squares methods to fit such surfaces. This work utilizes splines as a surface fitting tool. Splines are a useful tool because the derivatives required for a gradient based optimizer can be readily computed using various packages. Splines are shape preserving (i.e. convexity properties are unchanged). Constraints can be implemented when fitting splines.

This work demonstrates the application of the new spline based optimization procedure on a well placement problem. This example is based on a real 17 MMSTB oil field. The operators of the field planned to begin waterflooding. The optimization tool was used to plan the location (areally) of the water injection well. The well location determined using the tool is predicted to produce over 800 MSTB of incremental oil when compared to the original location proposed by the operators. The CPU requirements were modest, under 3% of the possible well locations were simulated. A history matching process is also demonstrated which is used to determine the ratio of vertical to horizontal permeability, a global porosity multiplier and the gas-oil contact depth.
Quantification of Depth Accuracy
Authors: Brooks A. , Wilson H. , Jamieson A. , McRobbie D. , Holehouse S. G.
Published: December 2007

Depth is a critical measurement in the economic development of a hydrocarbon asset. Almost all downhole activities, from making petrophysical measurements to setting packers, are performed remotely from surface. The common reference for all such activities is depth. A vertical depth error of less than one meter can have a financial impact counted in millions of dollars. However, despite the Industry's heavy reliance on depth, its accuracy is poorly specified.

This paper describes a set of error terms which allows proper quantification of along-hole depth uncertainty for commonly used measurement systems. Additionally, the terms include correlation coefficients that allow quantification of the relative uncertainty between two competing measurements.

Although the physical measurement that is made at the rig site is normally along-hole depth, it is vertical depth that defines the relationship between sub-surface features. The quantification of along-hole measured depth uncertainty is therefore only a partial solution; it is also necessary to estimate vertical uncertainty.

The directional survey of the wellbore defines vertical depth for any along-hole depth, and directional surveys are routinely accompanied by an estimate of positional uncertainty. A method is described for combining the directional survey's estimate of the wellpath's vertical position uncertainty with the along-hole depth uncertainty associated with another downhole operation, resulting in a valid vertical uncertainty for that operation.

Adoption of the techniques described in this paper will result in valid estimates of depth uncertainty, which it is hoped will encourage better depth management practices, and result in more productive wells.
3D Geological Modeling in a Turbidite System with Complex Stratigraphic-Structural Framework—An Example From Campos Basin, Brazil
Authors: Albertão G. A. , Grell A. P. , Badolato D. , dos Santos L. R.
Published: December 2007

After 3 years of production, results indicated necessity to refine the geological model of Cretaceous turbidite reservoirs in an off-shore oil field of Campos Basin, Brazil.

A stratigraphic analysis was developed to build a new stratigraphic-structural framework. Seismic interpretation was used to incorporate structural data by mapping the system of normal faults. Using concepts of sequence stratigraphy, seismic, biostratigraphic and lithologic data were used to define 12 major depositional sequences, spanning from Cenomanian to Maastrichtian. In 8 of these sequences, 12 turbidite systems were recognized and 9 of them focused for the present study. These turbidite systems compose the operational reservoir zones. Six of them were deposited during the Turonian and three during the Santonian. Erosive surfaces and regional unconformities affect the distribution of the turbidite systems. Action of erosion and faulting results in complex framework and lateral communications among reservoirs of different ages. Several oil-water contacts are present and controlled by some of the faults and the lateral communications.

Modeling this complex system included many different techniques and softwares in steps of the work. The first step involved a topologic three-dimensional construction, including all of the major geologic information; relationships among the main turbidite systems were validated by production data. Next was creating a refined grid to populate the model with rock-properties; corner point geometry grid was built to honor the direction of major faults. Third was facies characterization; vertical proportion matrix was used to represent the horizontal non-stationary of the data and seismic amplitude was used as a constraint. Plurigaussian simulations were used to populate the model; this type of simulation is suitable to represent the multiple and non-sequential contact relations among facies. The fifth step was using Monte Carlo simulation to fulfill the model with porosity and permeability, based on petrophysic histograms from well data, classified by facies. Upscaling the model was the last step in order to finally transfer the geological data to the flow simulator.

Preliminary results from the flow simulator reveal better fitting between this new geological model and the present production data.
Analysis of Gas-Cycling Performance in Gas/Condensate Reservoirs Using Neuro-Simulation
Authors: Ayala L. F. , Ertekin T.
Published: December 2007

The study of gas-condensate reservoirs has been a fertile area of research in the last decades, especially because of their singular depletion behavior which cast them apart from other types of oil and gas reservoirs. Typically, exploiting a gas-condensate reservoir without pressure maintenance generates high surface gas recoveries with relatively low condensate recoveries. Appearance of a hydrocarbon liquid phase upon isothermal depletion is typical of these systems, and major concerns arise related to the loss of this valuable fraction of heavier hydrocarbons and the associated impartment in gas production around the wellbore region. As a consequence, the injection of either surface gas or other gases such as nitrogen is common for pressure maintenance purposes. Pressure maintenance is economically justified by keeping the reservoir pressure above dew point or revaporizing any valuable condensate that might have formed. The convenience of the gas injection operation for a specific gas-condensate reservoir is strongly tied to the flow characteristics of the reservoir and phase behavior of the fluid. Highly sophisticated and expensive compositional simulations are usually employed in order to calculate reservoir performance under gas-cycling operations. In this study, we propose the implementation of artificial neural network (ANN) technology towards the establishment of an expert system capable of learning the existing vaguely understood relationships between the input parameters and output response of compositional simulation of gas-cycling operations in gas-condensate reservoirs. Parametric studies are conducted which identify the most influential reservoir and fluid characteristics in the establishment of optimum production protocols for the implementation of the pressure maintenance operation. As a result, a powerful tool for the implementation of pressure maintenance operations in gas-condensate reservoirs is developed. This tool is capable of assisting in designing an optimized exploitation scheme for a particular reservoir under consideration for development. Fast, reliable, and inexpensive results are obtained using the proposed approach while capturing the important flow and thermodynamic characteristics inherent to such systems without resorting to detailed and expensive compositional simulation studies.
The Quest for Improved Proppant Placement: Investigation of the Effects of Proppant Slurry Component Properties on Transport
Authors: Brannon H. , Wood B. , Wheeler R.
Published: December 2007

Beyond the initial fracture propagation, the primary function of fracturing fluids is to provide the means and media for the transport and placement of a conductive proppant pack in the created fracture such that resident hydrocarbons may be more easily produced. That is after all, the objective of hydraulic fracture stimulation. Fracturing fluids have undergone great scrutiny in recent years, leading to significant effort and expense expended in the quest to develop the "perfect" system. Historically, these efforts have been akin to the proverbial dog chasing his tail, rather than on addressing the engineering objective of the designated location of a conductive propped fracture. Primary development focus has been on optimization of fluid rheological stability to get the treatment "in the hole" and then, secondarily, on mitigating the damage caused by "new and improved" fluid system. Unfortunately, post-stimulation production analysis frequently demonstrates effective fracture area far less than that designed, suggesting either that the proppant-pack is damaged far more than expected or that the proppant was not placed in designated areal location. The latter could be due to inadequacies in terms of the lateral transport away from the wellbore (length) and/or in vertically covering the productive interval (height).

Many low permeability reservoirs are now experiencing a renaissance in the application of high rate slickwater fracs. The slickwater treatments are typically designed for long fracture lengths even though such fluids are thought to have inherently poor proppant transport abilities, hence the high rate.

Recent testing was conducted in a large-scale slot apparatus to evaluate the relative effects of proppant slurry component characteristics and the proppant transport capability. The effects of various fluid specific gravity, fluid viscosity, proppant specific gravity, proppant size, slurry flow rate, and slot width were investigated. Testing included fluids from slickwater to gelled, weighted brines, proppants from 40/70 Ottawa sand to 14/30 ultra-lightweight proppants, pump rates from 0.1 to 1.0 bbl/ft/min, and slot widths from 0.25 to 0.5 inch. This paper will provide evaluation of the proppant transport testing data and discuss the comparative abilities of current fracturing slurry system technologies to achieve placement of a productive propped fracture.
Value-Based Allocation and Value Adjustment on Mixed-Quality Commingled Natural Gas Pipelines
Authors: Telesford A. L. , Telesford A. L.
Published: December 2007

This paper presents an insight into the thorny issue of ensuring, through allocation and value adjustment, that parties on a joint or commingled system receive their share of the thoroughly mixed end products and proposes a novel methodology for accomplishing this in an operable and equitable manner.
Prediction of Sand Production Rate in Oil and Gas Reservoirs: Field Validation and Practical Use
Authors: van den Hoek P. J. , Geilikman M. B.
Published: December 2007

This paper presents a model for the prediction of sand volumes and rates for any type of clastic oil or gas reservoir. This model captures both the geomechanical aspects (rock deformation and failure) and the transport aspects (e.g. role of drawdown and watercut) of the sand production problem.

An extensive model validation is presented in which the predicted sand volumes and rates are compared with field observations for a variety of oil and gas fields under various stages of depletion. For all these cases, the model predictions and field observations are in reasonable to good agreement.

In addition, a discussion is presented on how the model can be practically used. This discussion clearly demonstrates that sand production behaviour is not only dependent on in-situ stress, rock strength, and drawdown, but also very much on how the field is actually operated / managed at a detailed level.
A New Concept of Chemical Sand Consolidation: From Idea and Laboratory Qualification to Field Application
Authors: Kotlar H. K. , Haavind F. , Springer M. , Bekkelund S. S. , Torsæter O.
Published: December 2007

The conceptual idea is to give the porous matrix of the formation some additional residual strength to enhance the maximum sand free rate (MSFR).

Sand production in weakly consolidated reservoirs will occur when tensions in the well/perforation tunnel walls are large enough to disrupt the binding between the individual sand grains. This will generate a plasticized layer of sand in the near well bore area. The layer will erode by the produced fluid and be transported to the surface. The rate of erosion will depend on the residual strength of the plasticized zone and of the hydrodynamic forces acting on that particular zone.

There is field evidence indicating a residual strength corresponding to the capillary force in water-wet sand to be sufficient in stopping or limiting the sand production substantially. Thus, only a small increase in residual strength of the plasticized sand would make large contribution for enhancing the MSFR. This will have large economical implications in fields with wells controlled by MSFR, and particularly in the decline phase in which the field is well controlled by the well potential.

Since the criteria for strength are quite low, search for potential treatment chemicals could be carried out in areas completely different from the traditional chemicals used in sand consolidation. Three different chemical systems have been investigated and one chemical has been brought further for laboratory qualification and field use at a North Sea Field.

In order to carry out a full field test, challenges regarding water contamination, long horizontal wells with difficult placement and zonal coverage, and complex polymerization mechanisms in the carrier fluid had to be addressed. Some of these challenges and field experiences will be presented and discussed to gain valuable knowledge for future chemical sand consolidation operations.
New High-Performance Completion Packer Selection and Deployment for Holstein and Mad Dog Deepwater Gulf of Mexico Projects
Authors: Fitzgerald A. , Harpley G. , Hupp J. , King J. G.
Published: December 2007

The BP Holstein and Mad Dog oilfields in the Gulf of Mexico are high-profile deepwater projects (4,300 and 4,400 ft water depth) with high production and high costs. Wellbore construction for both fields includesd a completion packer to manage tubing loads and reliably isolate production fluid and pressures from the casing, tiebacks, and risers.

Several drivers influenced the packer selection and development process. The magnitude of the packer loading pointed toward high-performance permanent packers. Life- of- well and life- of -field requirements for possible planned and unplanned workovers pointed toward the operational flexibility of retrievable packers. High rig costs, a desire for accelerated production, and difficult wireline access "S" curve wells indicated the value derivable from interventionless completions. And the high cost of failure pointed toward high performance and quality standards to reduce risk of failure and potential malfunctions. Together, these drivers pointed toward a new packer solution. Ultimately a high- performance, modular, removeable, "V0 rated," interventionless production packer was developed which met all of these criteria. This paper describes the Mad Dog Holstein and Mad Dog Holstein completion environment, and details the selection, development, deployment, and lessons learned with the hydrostatic set, interventionless, removeable packer solution.
Optimizing the SAGD Process in Three Major Canadian Oil-Sands Areas
Authors: Shin H. , Polikar M.
Published: December 2007

The SAGD process has already been implemented for commercial production in Alberta. In this study, SAGD operating conditions were optimized through numerical reservoir simulations in the three oil sands areas using characteristic properties. Several parameters were screened to define the most applicable reservoir conditions for the SAGD process. The product of reservoir thickness and permeability (k×h) was found to be the single most important parameter. Finally, the optimal cases for each area were compared.

The simulation results for shallow Athabasca-type reservoirs showed that a net pay thickness of 15 m is still economic for the SAGD process because of the high permeability of this type of reservoir, despite the very high bitumen viscosity at reservoir conditions. For Cold Lake-type reservoirs, a net pay thickness of at least 20 m is required for an economic SAGD implementation. In Peace River-type reservoirs, net pay thicker than 30 m might be required for a successful SAGD performance due to the low permeability of this type of reservoir.

The results of the study indicate that the shallow Athabasca-type reservoir, which is thick with high permeability (high k×h), is a good candidate for SAGD application, whereas Cold Lake and Peace River-type reservoirs, which are thin with low permeability, are not as good candidates for conventional SAGD implementation.
Optimal Coarsening of 3D Reservoir Models for Flow Simulation
Authors: King M. J. , Burn K. S. , Wang P. , Muralidharan V. , Alvarado F. , Ma X. , Datta-Gupta A.
Published: December 2007

We have developed a new constrained optimization approach to the coarsening of 3D reservoir models for flow simulation. The optimization maximally preserves a statistical measure of the heterogeneity of a fine scale model. Constraints arise from the reservoir fluids, well locations, pay/non-pay juxtaposition, and large scale reservoir structure and stratigraphy. The approach has been validated for a number of oil and gas projects, where flow simulation through the coarsened model is shown to provide an excellent approximation to high resolution calculations performed in the original model.

The optimal layer coarsening is related to the analyses of Li and Beckner (2000), Li, Cullick and Lake (1995), and Testerman (1962). It differs by utilizing a more accurate measure of reservoir heterogeneity and by being based on recursive sequential coarsening, instead of sequential refinement. Recursive coarsening is shown to be significantly faster than refinement: the cost of the calculation scales as (NX·NY·NZ) instead of (NX·NY·NZ)[2]. The more accurate measure of reservoir heterogeneity is very important; it provides a more conservative estimate of the optimal number of layers than the analysis of Li et.al.. The latter is shown to be too aggressive and does not preserve important aspects of the reservoir heterogeneity. Our approach also differs from the global methods of Stern (1999) and Durlofsky (1994). It does not require the calculation of a global pressure solution and it does not require the imposition of large scale flow fields, which may bias the analysis, Fincham (2004). Instead, global flow calculations are retained only to validate the reservoir coarsening.

Our approach can generate highly unstructured, variable resolution, computational grids. The layering scheme for these grids follows from the statistical analysis of the reservoir heterogeneity. Locally variable resolution follows from the constraints (reservoir structure, faults, well locations, fluids, pay/non-pay juxtaposition). Our reservoir simulator has been modified to allow a fine scale model to be initialized and further coarsened at run time. This has many advantages in that it provides both simplified and powerful workflows, which allow engineers and geoscientists to work with identical shared models.
Streamline-Based Production-Data Integration in Fractured-Reservoir Characterization and Its Application
Authors: Shen F. , Li S.
Published: December 2007

An integrated fracture modeling process is developed by incorporating different disciplines and scales from static data reservoir characterization to streamline-based dynamic data calibration. The geometry and continuity of reservoir properties need to be modeled before characterizing fractures. The geological structure based geomechanical analysis, rock physics modeling and azimuthal seismic anisotropy techniques are applied to deriving strain and stress properties, seismic anisotropy. The fracture orientations and density can be identified with these attributes and validated in wells with image logs. The obtained fracture distribution is translated into fracture properties at wells by incorporating geo-mechanical in-suit stress information to identify open fractures and to determine the effective fracture aperture. The spatial geo-mechanical information is useful in predicting the variations of fracture aperture. The coupling flow between the fractures and matrix is considered in the modeling of initial effective permeability tensor. The streamline based flow simulation is performed to match observed reservoir pressure responses at wells. The inferred permeability field can be used to examine the orientations of the major directional flow. By comparing to the fracture distributions characterized with static data, the fracture spatial connectivity can be calibrated. The calibration of fracture permeability is proved to be an efficient way to characterize the complexity of nature fracture system. Streamline simulator can efficiently handle large reservoir models. The application of the modeling process to the case study shows that this is a significant step toward making dynamic data integration in fractured reservoir characterization.
Downhole pH Measurement for WBM Contamination Monitoring and Transition Zone Characterization
Authors: Raghuraman B. , Xian C. , Carnegie A. , Lecerf B. , Stewart L. , Gustavson G. , Abdou M. K. , Hosani A. , Dawoud A. , Mahdi A. , Ruefer S.
Published: December 2007

Formation water sampling is important for understanding corrosion and scaling potential of the water, characterizing hydrocarbon/water transition zones, determining compatibility between injection water and formation water, and determining optimal salinity and pH windows for polymer and gel injections. To obtain good quality formation water samples with wireline formation testers in wells drilled with water-base mud (WBM), it is important to track mud filtrate contamination by distinguishing between formation water and mud filtrate in real time while sampling. Current techniques typically use a resistivity sensor to monitor this contamination in real time. However, this works only when there is sufficient resistivity contrast between the filtrate and the formation water. Another technique involves addition of a colored tracer dye to the drilling mud and then monitoring the tracer concentration with an optical detector in real time.

In this paper, we present results from a Middle East production well in which a new downhole pH measurement sensor was deployed on a formation wireline tester. The sensor uses pH-sensitive dyes that change color according to the pH of the water sample. The pH of the formation water is a key water chemistry parameter that can alter because of temperature and pressure changes surrounding the sample as it is brought to surface. Hence, to obtain accurate values, pH must be measured in real time at downhole reservoir conditions. In addition to successfully measuring pH downhole, results from this field test show that pH can also be used to qualitatively monitor mud filtrate contamination in real time. This takes advantage of the fact that the mud filtrate pH is typically much higher than the pH of formation waters. Multiple pH measurements during sampling showed a good match with cleanup trends determined independently using a colored tracer added to the mud. Simulations using some typical formation water and mud filtrate samples indicate that the pH dependence on contamination is a complex function depending on several factors including composition, buffer capacity, ion equilibria, ionic strength, temperature, and pressure. This makes quantitative estimation of contamination from pH measurements difficult; nevertheless, qualitative tracking of cleanup trends is possible and useful.

The ability to differentiate between formation water and mud filtrate pH is also useful in characterizing oil/water transition zones and delineating oil/water contacts by scanning formation fluid samples at different depths.

Both of these downhole pH measurement applications improve the efficiency and success rate of sampling with wireline formation testers.
Incorporating 4D Seismic Data in Reservoir Simulation Models Using Ensemble Kalman Filter
Authors: Skjervheim J. -A. , Evensen G. , Aanonsen S. I. , Ruud B. O. , Johansen T. A.
Published: December 2007

A method based on the ensemble Kalman filter (EnKF) for continuous model updating with respect to the combination of production data and 4D seismic data is presented. When the seismic data are given as a difference between two surveys, a combination of the ensemble Kalman filter and the ensemble Kalman smoother has to be applied. Also, special care has to be taken because of the large amount of data assimilated. Still, the method is completely recursive, with little additional cost compared to the traditional EnKF. The model system consists of a commercial reservoir simulator coupled to a rock physics and seismic modelling software. Both static variables (porosity, permeability, rock physic parameters, etc.) and dynamic variables (saturations and pressures) may be updated continuously with time based on the information contained in the assimilated measurements. The method is applied to a synthetic model and a real field case from the North Sea. In both cases, the 4D seismic data are different variations of inverted seismic. For the synthetic case, it is shown that the introduction of seismic data gives a much better estimate of reservoir permeability. For the field case, the introduction of seismic data gives a very different permeability field than using only production data, while retaining the production match.
Molecular Structure and Aggregation of Asphaltenes and Petroleomics
Authors: Mullins O. C.
Published: December 2007

Tremendous strides have been made recently in asphaltene science. Many advanced analytical techniques have been applied recently to asphaltenes elucidating many asphaltene properties. The inability of certain techniques to provide correct asphaltene parameters has also been clarified. Longstanding controversies have been resolved. For example, molecular structural issues of asphaltenes have been resolved, in particular, asphaltene molecular weight is now known. The primary aggregation threshold has recently been established by a variety of techniques. Characterization of asphaltene interfacial activity has advanced considerably. The hierarchy of asphaltene aggregation has emerged into a fairly comprehensive picture - essentially in accord with the Yen model with the additional inclusion of certain constraints. Crude oil and asphaltene science is now poised to develop proper structure-function relations that are the defining objective of the new field - Petroleomics. The purpose of this paper is to review of these developments in order to present a more clear and accessible picture of asphaltenes - especially considering that the asphaltene literature is a bit opaque.
Reservoir Initialization in Two-Phase Hydrocarbon Reservoirs from Well PVT Data
Authors: Nasrabadi H. , Firoozabadi A.
Published: December 2007

In a reservoir with a gas cap and an oil column, natural convection can play a significant rule in species distribution in both gas and oil phases. In this work, we are interested in computing the species distribution in such reservoirs based on a given pressure and composition from a well in addition to permeability and temperature profiles. We present the formulation of the problem and take into account thermal, molecular and pressure diffusion in addition to natural convection. Results from numerical calculations show that the location of the GOC is significantly affected by both natural convection and diffusion. Numerical results also reveal that the distribution of species is affected by both natural convection and thermal diffusion.
Achieving True Sandstone Reservoir Stimulation in Deepwater Horizontal Wells
Authors: Mendez A. , Neumann L. F. , de Almeida Pinto E. , Torres R. , Farias R. , Acosta M.
Published: December 2007

In offshore horizontally completed wells, an acid job is usually pumped to remove the filter cake, previously created to allow sand control equipment and gravel be placed across the entire extended section. When such wells are acidized to remove the filter cake with a hydrochloric: hydrofluoric acid mixture, the resulting skin values are still in the positive range.

An improved HF acid system has been introduced in the Campos Basin-offshore Brazil with outstanding results. The HF acid system uses an organophosphonic acid complex to control the generation of HF and to dramatically reduce potentially damaging secondary and tertiary precipitates.

This paper describes the results of field treatments showing truly stimulated wells with negative skins - a first in this Campos Basin field for deepwater horizontal wells. Case histories with conventional regular hydrochloric: hydrofluoric acid mixture and with the improved acid system used will be presented. Laboratory core flow tests were performed in advance of the field program with seven different acid blends.Only one acid blend resulted in complete mud damage removal and true stimulation. Innovative equipment design, a state-of-the-art vessel with real-time monitoring capabilities, improved placement techniques and environmentally-friendly materials, are helping to transform acidizing into a valuable method in the quest for optimum performance from every injector, oil and gas well asset.
Optimal Well Completions Using Radial Profiling of Formation Shear Slownesses
Authors: Sinha B. , Vissapragada B. , Kisra S. , Sunaga S. , Yamamoto H. , Endo T. , Valero H. P. , Renlie L. , Bang J.
Published: December 2007

Borehole sonic data can be useful for various design decisions in the oil and gas industry; e.g., well planning, wellbore stability, and reservoir management. Optimal well completions require both the detection and estimation of the radial extent of near-wellbore alteration in reservoir intervals. We have analyzed borehole sonic data from a new tool that contains 8 azimuthal receivers at 13 axial positions with an inter-receiver spacing of 6 in. The large number of receivers together with new processing algorithms enables reliable modal decomposition and slowness dispersion estimates. We present results from the Backus-Gilbert inversion of cross-dipole and Stoneley dispersions that yields radial profiles of three shear slowness in the three orthogonal planes. We show theoretical validation of the dipole and Stoneley radial profiling of the shear slowness algorithms using synthetic dispersions for known variations in the compressional and shear slownesses. The inversion algorithms account for the sonic tool effects on dispersion data. Inversion of cross-dipole dispersions yields radial profiles of the fast and slow dipole slownesses averaged over the two opposite quadrants. In contrast, the Stoneley radial profiling algorithm outputs azimuthally averaged shear slowness in the cross-sectional plane of the borehole. Inversion of cross-dipole and Stoneley dispersions yields three shear slowness logs at various radial positions away from the borehole surface.Near-wellbore softening and stiffening are characterized by larger and smaller shear slownesses than those in the far-field. Identification of near-wellbore softening caused by mechanical damage aids depth selection for wireline pressure measurements to avoid sections that are prone to seal failures. In addition, it can help identify mechanically competent depth intervals for stimulation. We illustrate shear slowness profiling results from sonic data acquired in a few wells in the North Sea. This study has demonstrated a consistent correlation between a negligibly small difference between the near-wellbore Stoneley and dipole shear slownesses and negligibly small fluid mobility implying tight zones where fluid samples could not be extracted. The radial extent of mobility impairment is estimated from radial profiles of both the Stoneley and dipole slownesses that help in designing optimal perforation tunnels extending beyond the damaged annulus.