bluuebunny/crossref_metadata_2025 huggingface dataset:
Relative Permeability in Dual-Porosity Porous Media
Authors: Deghmoum A. H. , Tiab D. , Mazouzi A.
Published: December 2007

Reliable relative permeability data is an essential input parameter in reservoir engineering, most significantly in the area of reservoir simulation of dual-porosity systems. However, measurements of relative permeability do not work well because of laboratory limitation. Also, reservoir core samples are generally extracted from zones, where induced or natural fractures are absent. Obviously, data obtained from these cores may not reflect the real behavior of naturally fractured reservoirs. Because of this laboratory limitation, many commercial reservoir simulators neglect the effect of dual porosity on relative permeability, and implicitly assume that relative permeability is a straight line. This assumption in naturally fractured systems may lead to erroneous results.

The purpose of this study is to rectify these shortcomings by laboratory experimental contribution. Thus, the main objectives are: (a) to perform special core analyses on Berea outcrop core samples as a model of rock. (b) to simulate fracture opening, by cutting these samples in such away to get different fracture apertures. (c) to investigate the effect of dual porosity on the shape of capillary pressure curves, and (d) to evaluate the effect of fracture opening on both absolute and relative permeability.

A good correlation between absolute permeability and fracture aperture is obtained. The effect of dual porosity is clearly observed on capillary pressure curves. Unsteady-state tests could not be used to measure relative permeability on these specially prepared core samples. This is due to the fact that fractures become the easiest pathway for water flow, which results in high residual oil saturation in the matrix. However, the centrifuge technique test is run with success because both matrix and fracture are subjected to the centrifuge field.

These findings are extended to actual naturally fractured reservoir (NFR) in Algeria. Tin Fouye Tabankort (TFT) reservoir is selected as a prototype of Algerian NFR. Availability of naturally fractured cores and published data are the principal reasons for this selection. A discussion of TFT natural fracture indicators is presented, including: core observations, well test analysis and borehole imager tools. Displacement test is conducted on a full diameter core in order to solve the laboratory limitations and to obtain representative data of relative permeability. These laboratory tests indicate the existence of a good correlation between permeability and fracture opening. The correlation is used to estimate the aperture of natural fractures in TFT reservoir. This study may also lead to the development of a laboratory technique for systematically determining the fracture intensity index.
The Benefits of In Situ Upgrading Reactions to the Integrated Operations of the Orinoco Heavy-Oil Fields and Downstream Facilities
Authors: Kuhlman Myron
Published: December 2007

The value of heavy-oil production is reduced because extra refining is required to market the oil and a diluent may be needed to transport the oil. In some reservoirs, insitu pyrolysis reactions can remove this limitation.

The oil in most reservoirs produced by steam-drive is not hot long enough for pyrolysis to drastically change properties of the oil. However, deep, high permeability, thick formations like the Orinoco tar belt offer a new opportunity. When steam is injected at a pressure above 8.93 M Pascal (1300 psi), and the production is constrained, large volumes of 10 API oil can be upgraded underground to 25 API oil. Moreover, production from the reservoir more than doubles, and the coke and sulfur are left underground. Since the viscosity of the produced crude is reduced several orders of magnitude, no diluent would be needed to transport the crude. Finally, much lighter oil arrives at the refinery, so extra investment in distillation and cracking equipment is unnecessary.

Thus, in situ upgrading could reduce the investment needed to market heavy oil, generate higher profits and make smaller reservoirs more attractive for development.
McKittrick Reservoir Modeling Study: Operation and Redevelopment Strategy
Authors: Chiou C. S. , Lentz W. D. , Nisenbaum Y. , Langen R. A.
Published: December 2007

This paper describes a reservoir modeling study that integrates 3D geological modeling with thermal simulation. The objective of the study was to optimize the steam injection schedule and establish a redevelopment strategy for the Tulare reservoir in the McKittrick field. 3D geological interpretation and visualization technology helps capture detailed heterogeneity to properly represent relevant flow units and barriers. The reservoir model was validated by history matching 10 years of field performance. Modeling past performance has identified weaknesses in reservoir description and suggested modifications that were needed to improve the model.

Forecasts of future performance were made under different operating conditions and redevelopment scenarios. Simulation results show that the steamflood efficiency and project profitability can be improved by reducing current steam injection. Evaluation of various development scenarios indicates that twinning the injection wells, to separately provide steam injection support to the upper and more mature, lower sands, makes a significant improvement on production performance and project economics.
Precise Tiltmeter Subsidence Monitoring Enhances Reservoir Management
Authors: Davis E. , Wright C. , Demetrius S. , Choi J. , Craley G.
Published: December 2007

Subsidence monitoring is most commonly conducted using either level surveys or GPS surveys of elevation monuments to determine changes in elevation across a field as a result of injection and production activities. Several operators near Bakersfield, CA are using tiltmeter-based subsidence monitoring to obtain highly detailed maps of subsidence with continuous data acquisition. The tiltmeter measured subsidence is then correlated to production and injection on a day-by-day basis so the impact of individual injection and production events can be quantified. The data is presented in a video format that allows visual assessment of the field motion. In some fields, the monitoring array is also equipped with monuments for periodic level survey and GPS measurements of the ground motion.

This paper discusses the design and installation of tiltmeter subsidence monitoring arrays and the format of the results. In addition, the subsidence data is correlated to field activities to show how the monitoring can be used to correlate ground movement with reservoir events.
A New Approach for Most Realistic Wellpath Computation
Authors: Gfrerrer A. , Glaser G. P.
Published: December 2007

The trajectory of a wellpath is a tortuous space curve with permanent changes in directions and curvatures. A usage of steerable directional drilling tools in nowadays drilling practices even more forces the bit apart from its natural tendencies of running a smooth course - enforcing a highly curved shape of the well. Although this is well known all to the author's knowledge existing wellpath computation methods are based on piecewise approximating the wellpath with constant curvature linear, circular and helical curves and arcs.

A new proposed trajectory computation method gives up these old paradigms and introduces a new approach to accurately calculate the spatial course of a wellpath while maintaining its realistic shape from standard wellbore survey measured depth, inclination and azimuth data. In detail the discussed algorithm is founded on fundamental differential geometry practices in synergy with piecewise spline-curve approximation techniques. This limits the common problems of spline-curve approximations. The result is a highly accurate wellpath description with proven curvature continuity in any position along its course.

The proposed new method is a further step in more accurate wellbore trajectory and dogleg severity computation- especially for complex shaped and extended reach wells. The proposed model's accuracy and reliability is proven and verified with a complex shaped, 11.3 km synthetic wellbore example (with known results) followed by extended-reach and complex shaped field case studies.
Deriving Greater Business Value Through Improved Drilling Information Management
Authors: Bidi Mohammad Z. , Razak Rozalina Abd. , Jusoh Kamri
Published: December 2007

Well expenditure represents a significant part of Petronas Carigali Sdn Bhd's (PCSB) CAPEX where most of the cost comes from drilling. This has prompted the Drilling Department to continuously look for ways to reduce its drilling costs and be as efficient as possible. Back in 1996, PCSB embarked on a drilling initiative project so called DICE (Drilling Information and Communication Environment). The aims were to capture, store and analyze information relating to all PCSB drilling activities and operations. In support of this, a system was introduced whereby operations data were captured at offshore well sites and transmitted electronically to a central office database for drilling analysis and future reference.

More recently, the primary focus of the project was to make better use of the valuable well data and information that had been collected, with particular emphasis on the derivation of drilling performance and cost metrics. Key to this was the development of a set of standard queries to interrogate the drilling database, and to derive performance information such as Drilling Days per Thousand Foot, Well Cost per Foot, NPT and other trends. This also provided the opportunity to perform a thorough data quality check on previous wells and to standardize the operations time breakdown and cost coding systems to ensure reporting consistency.

Besides gathering drilling activities and operations information, steps have been taken to also capture knowledge (i.e. lessons learnt) using the same database. Various customized reports were introduced to ensure effortless daily monitoring of drilling operations and standardization of the PCSB reporting system. The major customization work involved the introduction of an improved, automated, Final Well Report (FWR). This has tremendously reduced the time taken by drilling engineers for the preparation of Final Well Report at the end of each well.

Overall, by enhancing its drilling data management system, PCSB has been able to better monitor its drilling activities and to more readily identify opportunities to reduce its operational costs.
Technique for Close Cluster Well Head Concentrated High Quality and High Speed Drilling Cementing Surface Interval in Sz36-1d of Liaodong Bay
Authors: Wei Jiang
Published: December 2007

This paper summarizes the application of high quality and high speed concentrated surface drilling technique for the first time in drilling and cementing surface interval of 14 wells in 56 hours with average time of 3.99hr/well in phase II development of this field. The project was characterized by improvement mainly in 4 aspects: conductors were 15m shorter than normal; wellhead spacing reduced from 2m×2m to 1.5×1.8m; surface casing changed from seamless casing to erw casing; with additives; the strength of quick hardening cement reached 4.2MPa in 4 hours, 61% stronger, so the whole operation process was safe and smooth compared with that of Block J, which was the fastest then, the efficiency was improved by 55.7%, 3 hours saved each well. The success of this technique had 3 significant meanings: broke the wellhead spacing of 2m×2m and realized the close wellhead spacing of 1.5m×1.8m successfully, so the wellhead platform dimension and project cost were; realized the quick hardening cementing of low temperature surface interval, resolved the leakage on concentrated drilling and cementing surface interval, explored the method of surface open-hole volume calculation, which laid basis for the concept of close wellheads and big platform and provided reference experience for the phase II overall development of SZ36-1 oil field.
Large-Scale Comparative Study of Prepacked Screen Cleanup using Acid and Enzyme Breaker
Authors: Asadi Mahmoud , Penny Glenn S.
Published: December 2007

Some of the completion failures are due to screen plugging. A number of remedies have been adopted by the industry to cleanup plugged screens. However, these cleanup methods are not investigated under downhole conditions. This study utilized a large-scale radial flow-loop to study prepacked screen cleanup under downhole conditions. First, the original permeability of each screen was measured with 10 ppg NaCl brine solution. A sized carbonate drill-in-fluid was then formulated and pumped for 3 hours and at a constant differential pressure of 60 psi across the screen, simulating a screen run in a wellbore. Inlet and outlet samples were collected for size distribution analysis and removal efficiency calculations of each screen. Each plugged screen was then subjected to a cleanup method such as acidizing, use of enzyme breaker, backflow, or a combination of these methods. Following cleanup, the permeability of each treated screen was measured with 10-ppg NaCl brine solution and compared to the screen's original permeability. The degree of plugging and percent area open to flow was evaluated based on the retained permeability of each screen.
Drilling Fluid Optimisation Study for K-Shale in the Malay Basin
Authors: Tan C. P. , Willoughby D. R. , Yaakub Mohd Azriyuddin , Chen X. , Hamid Pauziyah Abdul , Ibrahim Zamanuri , Ibrahim Zahari
Published: December 2007

Drilling experience in K-shale in the Malay Basin (South China Sea, Malaysia) highlighted the issue of wellbore stability in the formation. A wide range of drilling problems has been experienced, ranging from tight hole to stuck pipe. Subsequently, a collaborative project between CSIRO Petroleum and Petronas Research & Scientific Services Sdn Bhd was conducted to address the problems. The aim is to develop a technical framework of drilling fluid design and consolidated into a methodology for overcoming wellbore instability-related problems in the shale.

This paper describes the outline of the project and the approach adopted in the development of the methodology. The approach is based on drilling fluid-shale interaction and proven rock mechanics principles. Based on the gathered drilling experience and laboratory tests conducted on downhole core material, dominant failure mechanisms of the shale were identified. Examples of critical mud weight contour plots and design charts of pressure change (due to drilling fluid-shale interaction mechanisms) which form part of the consolidated methodology for designing optimal drilling fluid are presented. The methodology provides a pragmatic approach for managing shale instability problems in drilling extended reach wells in the Malay Basin as well as other regions worldwide. The approach would result in an increase in drilling efficiency and a reduction in drilling cost.
Time-Dependent Wellbore (In) Stability Predictions: Theory and Case Study
Authors: Abousleiman Y. , Ekbote S. , Tare U.
Published: December 2007

Time-dependent wellbore (in)stability during oil and gas drilling account for a significant amount of lost rig time and substantially increased drilling costs ($700 million annually according to conservative estimates). Coupled time-dependent processes have been previously described in the realm of the poroelasticity theory. This wellbore (in)stability modeling approach allows the drilling engineer to systematically include the stress variation around the wellbore and the associated rock deformation and pore pressure changes. In this paper, in addition to the analyses conducted on the previously derived solutions for thermal and pore fluid diffusion, the time-dependent solution for stresses and pore pressures considering the mud and formation shale activities are presented. These solutions are the basis of the software, PBORE-3D, which utilizes contemporary programming techniques and can perform analyses of stress/pore pressure, formation failure, mud weight, and mud-salinity design for drilling shale formations. The model is especially useful in the prediction and visualization of time-dependent break-outs created due to inadequate mud weights; as well as time-dependent alteration of the near wellbore stress concentration caused by excessive mud weights leading to lost circulation problems. A case study is presented in this work which demonstrates the straightforward application of the model to challenging drilling conditions.
Successful Isolation of a Loss Circulation Zone of a Short Radius Horizontal in a Highly Fractured Environment
Authors: Ubaidan A. Al , Esmail W. J. , Aborshaid H. , Umair M. Al
Published: December 2007

This paper addresses the successful isolation of a loss circulation zone of a short radius horizontal completion utilizing the cement retainer technique in a highly fractured environment. The process was applied to a well in a highly fractured carbonate reservoir undergoing pressure maintenance by water injection. Fracture orientation in the area is running mainly NE/SW. While drilling the horizontal section, complete lost circulation was encountered in the middle of the planned lateral section, most probably through a fracture. Circulation could not be regained by pumping LCM pills or placing cement plugs. The horizontal section had to be plugged and a new horizontal lateral was drilled in a different direction. A drillable squeeze packer was used to hold a good kick-off cement column above the loss circulation zone. Prior to the workover, the well was producing 3.3 MBOD at 47% water cut. The initial post workover test showed 3.0 MBOD restricted (choked) water-free production.
Petrophysical Measurements on Shales Using NMR
Authors: Martínez Gabriela A. , Davis Lorne A.
Published: December 2007

Shales are important constituents of petroleum systems, and it is necessary to study their petrophysical properties as both reservoir components and as seals. Nuclear magnetic resonance has proven to be a good technique for measuring the reservoir engineering properties of rocks. This paper presents measurements of NMR relaxation in shales. It establishes that shale petrophysical information is accessible using standard NMR lab techniques employed in the oil industry. Even for good seals, shale porosity and pseudocapillary pressure curves can be derived from NMR relaxation data. This opens the question as to whether NMR logging can be used to ascertain seal quality for oil and gas storage reservoirs and for CO2 disposal reservoirs.

NMR measurements were performed in a low field spectrometer primarily on shales characterizing seals. Multiexponential T2 and T1 relaxation rates were determined from CPMG and inversion recovery experiments, respectively. Mean log T2 values of the undersaturated samples were about 0.4 ms. The T2 relaxation times increased after the shales were saturated but remained below 2 ms. Porosity for each sample was derived from the T2 magnetization and calibrated against a standard. Since NMR detects total porosity, the porosity was generally larger than that determined from laboratory gas flow-saturation techniques. The T2 relaxation rate distributions were normalized using the total magnetization calibration and integrated from the larger times to yield pseudo-capillary pressure curves.
Drilling Engineering Challenges in Commercial SAGD Well Design in Alberta
Authors: Knoll R. , Yeung K. C.
Published: December 2007

Recently, the field pilots in Canada using SAGD (Steam Assisted Gravity Drainage) technology have generated sufficient positive response to encourage commercial scale development in the Alberta Oil Sands Deposits. This will be a very interesting time for drilling engineers, since SAGD well pairs present some unique design and operational challenges. This paper will attempt to review some of the drilling engineering challenges of generic SAGD well design in the Alberta setting, specifically, the need to cool the drilling mud to maintain hole stability, and the selection of slant or vertical intermediate hole section geometry.
An Innovative Approach for the Analysis of Production History in Mature Fields: A Key stage for Field Re-engineering
Authors: Coste J. -F. , Valois J. -P.
Published: December 2007

Mature fields are defined as fields with a relatively long production history (up to 70 years) and many wells drilled (up to 1000 wells). Generally, little data is available on these wells, therefore the analysis of the long production history for the understanding of field behavior is a key stage in the reservoir process prior to field re-engineering. This paper proposes a new approach for optimizing the analysis of production history: after the graphical analysis of the global data set, we applied non-linear regression methods to the oil rates, and smoothing methods to the water cut curves. We extract original indicators of production. Multivariate statistical analysis methods can then be applied with a new (robust) approach of clustering. This methodology consists in classifying wells by dividing the field into areas. Mapping of statistical results helps identify the production mechanisms and locate the poorly-drained zones which potentially contain remaining reserves. The method is illustrated by two field cases: the first one is a carbonate reservoir bearing light oil, and the other one is a shaly sandstone reservoir containing heavy oil.
Field Application of Production Analysis
Authors: Chu Wei-Chun , Cox S. A. , Gilbert J. V. , McCarthy C. J.
Published: December 2007

This work presents the application of the combined type-curve and decline-curve analysis methods to five distinct examples of continuously declining rate and pressure data. Examples of both volumetric and geopressured gas reservoirs are examined.

Production analysis is a powerful tool when used with traditional well testing techniques to obtain consistent results. Used in isolation the limitations of production analysis can lead to erroneous conclusions. The limitations of production analysis are proportional to (1) the quality of the production data (frequency, accuracy and extent) and (2) the uncertainty in the average reservoir pressure.

These deficiencies can be alleviated by judicious use of periodic buildups to quantify average reservoir pressure and to capture the transient behavior of the reservoir.
A New Approach to Gas Material Balance in Tight Gas Reservoirs
Authors: Engler Thomas W.
Published: December 2007

Gas material balance in conventional, volumetric reservoirs is described by a linear relationship between pressure/z-factor (p/z) and cumulative production. Unfortunately, tight gas reservoirs do not exhibit this type of behavior, but instead develop a nonlinear trend, which is not amenable to conventional analysis. The nonlinearity is a function of two items: the testing method (time) and the reservoir characteristics. For these type of reservoirs the testing time is insufficient to reach average reservoir pressure and from a practical viewpoint, it is not possible to shutin for extended periods of time. Therefore, a method has been developed to use key intersection points and slopes from a tight gas material balance plot to better understand the reservoir behavior.

This work begins by explaining the nature of the nonlinear trend in terms of flow regimes. The primary objective is to improve the estimate of gas-in-place and recovery in a tight gas reservoir. Typically, gas-in-place is underestimated using conventional techniques. It is demonstrated that by using the appropriate slope with the initial pressure an improved (increased) estimate of gas-in-place is achieved. Furthermore, it is possible to distinguish the effect of infill wells and subsequently determine the incremental recovery. Included are field examples from the San Juan Basin and southeast New Mexico, which demonstrate the technique.
Gas Shutoff Evaluation and Implementation, North Slope, Alaska
Authors: Frankenburg A. , Bartel P. , Roberts G. , Hupp D.
Published: December 2007

Oil production on Alaska's North Slope has been limited as a result of gas production and the ensuing gas-handling facility constraints. Diagnosis of gas-production problems is complicated by the fact that many of the wells are high-angle or horizontal. This paper presents case studies in the diagnosis and treatment of excess gas production in three horizontal oil wells located on the North Slope of Alaska.

Candidate wells for gas shut-off (GSO) were identified based on gas flow rates and gas/oil ratio. Wells that were not commercially producible were selected for evaluation as potential GSO wells. These wells were assessed with new-technology logging tools conveyed on coiled tubing or with a downhole tractor. The new production logging technology provided direct gas and oil holdup measurements allowing for interpretation of three-phase production in the horizontal well environments. The goal was to identify dry gas production (i.e., gas production without associated oil production).

After dry gas production was identified, GSO procedures were designed based on the location of the gas entry into the wellbore. Two of the case studies involved GSO from the toe of the horizontal section of the wells, which was accomplished by placing a cast iron bridge plug on coiled tubing above the gas-producing perforations. The third case study identified dry gas production from the top perforated interval. This GSO involved setting a plug below the gas-producing perforations and squeezing them off. The plug was then drilled out using coiled tubing, and pushed to TD.

These techniques proved to be economical gas-shutoff solutions in difficult well environments, and each case resulted in significant reduction of free gas and increase in oil production.
Foamed Cement vs. Conventional Cement for Zonal Isolation—Case Histories
Authors: Kopp Kevin , Reed Shawn , Foreman Jay , Carty Brian , Griffith James
Published: December 2007

Data from six deep gas wells in Wyoming indicate that foamed cement outperforms conventional cement for zonal isolation. Two of the six wells were cemented across the production zones with conventional non-nitrified cements. These wells experienced outer-zone communication after the stimulation treatments. In the other four wells, the foamed-cement sheath provided zonal isolation even after the sheath was perforated and stimulation treatments were performed. The case histories described in this paper provide an opportunity to compare the performance of foamed cement to conventional cement on similar wells within a particular geographic area.

Large-scale laboratory testing has shown that foamed-cement is ductile and can deform as casing is pressurized, but will not crack like non-nitrified cement. These test results were confirmed by the results obtained in the six case-history wells. In the first two wells that were cemented, the operator used the conventional high-strength, non-nitrified cement across the formations. Tracer tags on the stimulation treatment showed that zonal isolation was not achieved and that the stimulation treatment communicated between the high- and low-pressure zones. The operator elected to use foamed cement for the last four wells to help obtain zonal isolation. In these wells, the stimulation treatment remained in the zone, little fracture growth occurred outside the target formation, and communication did not occur between the high- and low-pressure zones.

This paper provides details about the slurry design and job execution on the six case-history wells, and also presents the postjob analysis that verifies the conclusions.
Improved Saturation Determination in Thin-Bed Environments Using 2D Parametric Inversion
Authors: Jammes L. , Faivre O. , Legendre E. , Rothnemer P. , Trouiller J-C. , Galli M-T. , Gonfalini M. , Gossenberg P.
Published: December 2007

The analysis of deep-reading electromagnetic measurements is critical to the evaluation of hydrocarbon reserves. However, in thin bed formations, poor tool vertical resolution and corresponding low sensitivity to hydrocarbon presence make interpretation in the virgin zone difficult. A priori knowledge such as the formation geometry or auxiliary petrophysical information is necessary to overcome these difficulties.

This paper presents a prototype code developed by Schlumberger S-RPC in collaboration with AGIP. Using this code, wireline or LWD, laterolog and induction measurements can be more correctly analyzed in thinly bedded environments (2-D geometry, fluid invaded layers perpendicular to the borehole).

This code has been implemented in a software framework that provides a common environment specifically designed for electrical tool interpretation. Processing modules have a common interface and share common functionalities. Their organization reflects an implicit processing methodology, with progressive refinements that provides the interpreter with a robust and simple to use product, to better quantify reserves.

A preliminary step is to determine the formation geometry, which is carried out by detecting bed boundaries and representing the formation as a vertical sequence of layers. Petrophysical analysis can be invoked to characterize certain formation properties such as shale volume and porosity. These steps are performed prior to resistivity log measurement analysis and serve as a form of a priori knowledge.

Once the formation is described as a sequence of layers, wireline logging or logging while drilling (LWD) tool response can be computed using fast 2D simulators. The estimation of resistivity and the subsequent estimation of saturation will correspond to the minimization of a cost function, defined as the weighted squared difference between the measurement and the simulated response. Confidence outputs can be related to the local shape of the cost function at the end of the processing.

Two important advantages of the new code must be emphasized: (1) the possibility to choose among several petrophysical models to better describe the environment and determine directly parameters such as hydrocarbon saturation, and (2) the possibility to group together beds which are too thin or too close to each other to be analyzed independently, into a so called single optimization interval described by a reduced set of parameters.

This paper presents results obtained on selected benchmarks extracted from real data and compares them with those obtained through more traditional approaches.
Formation Electrical Anisotropy Derived from Induction Log Measurements in a Horizontal Well
Authors: Bang Jon , Solstad Arne , Mjaaland Svein
Published: December 2007

An existing theory describes how electrical anisotropy in the formation affects the response of resistivity logging tools. We have related this theory to the processing of LWD induction logs, and are thus able to calculate the anisotropic resisticities directly from the logs.

The method has been demonstrated by application to logs from a horizontal well section. Anisotropy ratios of 2-5, and occasionally higher values, were obtained for this formation. We also addressed the accuracy of these numbers by using independent sets of input logs. The results indicate that the logs are influenced by factors like invasion in addition to the anisotropy.

Our approach provides a fast and efficient computer algorithm. The output is calculated at the depths of the input logs; hence, the resulting anisotropy becomes a depth-dependent formation property.
Integrated Interpretation of 3D Seismic and Wireline Data to Delineate Thin Oil-Producing Sands in San Jorge Basin, Argentina
Authors: Torres-Verdín Carlos , Chunduru Raghu K. , Mezzatesta Alberto G.
Published: December 2007

Hydrocarbon-bearing sand units in San Jorge Basin, Argentina exhibit thicknesses between 0.5 and 15m, with a mean value of 1.5m. These sand units are associated with ephemereal and laterally heterogeneous fluvial architectures embedded within much thicker shale units of lacustrine and flood-plain origin. Tuffaceous laminations originated from pulses of volcanic activity are also present in the sedimentary column. In view of the wide range of spatial variability and size of porous sands, a typical well is planned to intersect vertically as many sand units as possible. The best producing sands have average porosities of 10% and permeabilities of a few millidarcies. There are several problems faced by the petrophysicist in assessing whether or not a given sand unit should be perforated, namely, (a) discrimination between oil- and water- bearing sands is not trivial because of very low salinity water, (b) there exist substantial vertical variations of effective porosity within an individual sand because of shale laminations, and (c) it is often impossible to assess lateral extent away from the well. We have successfully addressed most of these difficulties using an interpretation procedure centered about the full 2D inversion of wireline array induction data. Full 2D inversion of array induction data is necessary to accurately estimate shallow and deep resistivities, as well as invasion radii in light of significant shoulder bed effects. This procedure has been complemented with the use of borehole NMR data to provide estimates of effective porosity within individual sand units. Finally, we have made use of geostatistical inversion of 3D post-stack seismic data to estimate the lateral extent of hydrocarbon-bearing sands laterally away from the well. We present several application examples that yield results consistent with borehole testing and production data.
The Green Element Method for Numerical Well Test Analysis
Authors: Archer Rosalind A. , Horne Roland N.
Published: December 2007

To use pressure transient test data in computerised methods for integrated reservoir charcterisation numerical simulations of the well tests are typically required. Numerical artifacts occurring in the simulation must be avoided as much as possible so that they do not adversely affect the reservoir characterisation.

This work explores the advantages of a hybrid boundary element method known as the Green element method for modeling pressure transient tests. Boundary element methods are a natural choice for the problem because they are based on Green's functions, which are an established part of well test analysis. The classical boundary element method is limited to single phase flow in homogeneous media. This works presents formulations which give computationally efficient means to handle heterogeneity. The accuracy of the scheme is further enhanced by incorporating singularity programming.

Comparisons of the proposed Green element approach to standard finite difference simulation show that both methods are able to model the pressure change in the well over time. When pressure derivative is considered however the finite difference method produces very poor results which would give misleading interpretations. The Green element method in conjunction with singularity programming reproduces the derivative curve very accurately.
Optimal Uplayering for Scaleup of Multimillion-Cell Geologic Models
Authors: Li D. , Beckner B.
Published: December 2007

Geophysicists, geologists, and reservoir engineers can now routinely build reservoir geologic models with ten million geologic cells and more than one thousand geologic layers. This explosion in reservoir detail capability presents new challenges for existing upscaling methods. Uplayering (the first step of upscaling) is a technique that provides reservoir engineers with optimal geologic layer-grouping schemes for simulation model construction. Much uplayering is still done by hand by reservoir engineers. Even though some advanced methods can provide automatic tools for uplayering, they are limited in the applicable model size and are also computationally expensive. This paper presents a practical and efficient method for uplayering of multimillion-cell geologic models. The proposed method defines a displacing front conductivity, a combination of porosity, permeability, and facies (in terms of relative permeability, endpoint saturation, and various facies rules), as the uplayering property. Use of the new property ensures that the most important geologic features for fluid flow simulation can be preserved after uplayering. The new method utilizes a residual optimization technique to determine the optimal geologic layer-grouping scenario for a given number of simulation layers. The method is so efficient that multiple optimal grouping scenarios, from the one simulation layer model to the model consisting of all geologic layers, can be generated in a short time, allowing the inspection of all possible combinations of layer-grouping scenarios. A residual curve (the difference of the defined property between the fine-layer and coarse-layer models) is produced from exhaustive analysis of all possible layering combinations. Using the residual curve, engineers are able to determine the number of simulation layers needed based on their tolerance of possible loss of fine-layer geologic features. The uplayering method has been successfully employed in most of recent major reservoir study projects in Mobil and results from three of these studies will be included in this paper.
Condensate Banking Dynamics in Gas Condensate Fields: Compositional Changes and Condensate Accumulation around Production Wells
Authors: Wheaton R. J. , Zhang H. R.
Published: December 2007

A bank of condensate can rapidly build up around a producing well when bottom hole flowing pressure falls below dewpoint in a gas condensate field. This bank grows as reservoir pressure declines both impairing well deliverability of gas and causing loss of heavy components at surface. An understanding of the condensate banking processes is essential in predicting the behaviour of the wells and of the fields.

In this paper, a general theoretical treatment of condensate banking dynamics is attempted to show how the compositions of heavy components of a gas condensate change with time around production wells during depletion. A new component relative mobility term is defined and an analytical model is developed for this purpose. The dependence of condensate banking behaviour on the mobility terms and the way it varies with fluid pressure-volume-temperature (PVT)/vapour-liquid-equilibrium (VLE) properties and relative permeabilities is studied in some detail for a range of simple rich and lean gas condensate mixtures.

Results have showed that the newly-defined component mobility term is a critical parameter in the behaviour of condensate banking. Two distinct effects are recognized, one dominant in the near wellbore region and one which is more important in the far field. The compositional change of heavy component is shown to be particularly rapid in low permeability high yield reservoirs and where fluids are close the critical point. Natural steady state situations may not exist with regard to changes in mixture compositions. The reservoir permeability and variation of production rate have significant impacts on condensate accumulation near wellbore and on the way of how the condensate bank develops.

In summary, the aim of this paper is to introduce a new theoretical treatment of condensate bank formation and to use this as a basis to increased conceptual understanding of the processes involved.
Integrated Fractured Reservoir Modeling Using Both Discrete and Continuum Approaches
Authors: Ouenes Ahmed , Hartley Lee J.
Published: December 2007

A new approach that combines the use of continuum and discrete fracture modeling methods has been developed. The approach provides the unique opportunity to constrain the fractured models to all existing geologic, geophysical, and engineering data, and hence derive conditioned discrete fracture models. Such models exhibit greater reality, since the spatial distribution of fractures reflects the underlying drivers that control fracture creation and growth.

The modeling process is initiated by constructing continuous fracture models that are able to capture the underlying complex relationships that may exist between fracture intensity (defined by static measures, such as fracture count, or dynamic measures, such as hydrocarbon production), and many possible geologic drivers (e.g. structure, thickness, lithology, faults, porosity). Artificial intelligence tools are used to correlate the multitude of geologic drivers with the chosen measure of fracture intensity. The resulting continuous fracture intensity models are then passed to a discrete fracture network (DFN) method.

The current practice in DFN modeling is to assume fractures are spatially distributed according to a stationary Poisson process, simple clustering rules, or controlled by a single geologic driver. All these approaches will in general be overly simplistic and lead to unreliable predictions of fracture distribution away from well locations. In contrast, the new approach determines the number of fractures in each grid-block, based on the value of the fracture intensity provided by the continuous model. As a result, the discrete fracture models honor all the geologic conditions reflected in the continuous models and exhibit all the observed fracture features.

The conditioned DFN models are used to build a realistic and detailed model of flow in discrete conduits. There are two main areas where detailed discrete fracture models can be used: (1) Upscaling of fracture properties (permeability, porosity and σ factor) for input into reservoir simulators; and (2) Optimization of well-design, completion and operation based on an understanding of the inter-well scale flows.

For accurate results, the full permeability tensor is calculated for each grid-block based on flow calculations using generalized linear boundary conditions. Inter-well flows are analyzed in terms of the variability in flow paths, characterized by distance and time traveled, through the fracture network connecting injectors and producers.
Improved Reservoir Characterization through Evolutionary Computation
Authors: Romero C. E. , Carter J. N. , Zimmerman R. W. , Gringarten A. C.
Published: December 2007

Computer-aided history matching techniques are increasingly playing a role in the reservoir characterisation process. In general, these techniques provide a single solution that matches the observed data. It has been widely recognised that a solution found to a history matching problem is not unique, but alternative solutions are usually not sought, due to time and cost restrictions.

This paper describes how evolutionary computation can be used to obtain multiple possible solutions without repeating the history matching process. Once a geological and structural model has been defined, Genetic Algorithms are used to carry out hydrocarbon reservoir characterisation by conditioning the reservoir simulation model to production data (history matching). The proposed approach uses ideas from Darwinian evolutionary theory, combining genetic algorithms and geostatistical modelling to generate multiple reservoir descriptions.

The algorithms return a suite of solutions (corresponding to different realisations of the reservoir model) from which the reservoir team can select a representative group for further analysis. The solutions give history matches with a quality comparable to what might be achieved by hand. The method is relatively easy to implement, robust with respect to lost or corrupted solutions, cheap in terms of computational costs, and can be easily parallelised.
Equipment and Operation of Advanced Completions in the M-15 Wytch Farm Multilateral Well
Authors: Algeroy J. , Pollock R.
Published: December 2007

This paper describes the equipment, function, and benefits of the innovative multilateral well completion installed in the Wytch Farm M-15 well operated by BP Amoco. This completion enables production from two different sections of an oil reservoir. Effectively, it is a multilateral well equipped with advanced completion functions much like two wells but without doubling the construction expense. This advanced completion included three hydraulic wireline-retrievable flow-control devices and an electric submersible pump (ESP). In addition, downhole electronic instruments provide monitoring of pressure, temperature, and flow.

Surface controlled, hydraulically operated, downhole actuators are used to effect flow control from each lateral of the well. The actuators have been designed using Surface Controlled Sub Surface Safety Valve (SCSSV) technology. Hydraulic pressure from surface positions the stepwise actuator, which in turn places the choke of the Retrievable Flow Control valve to any of 5 open or a closed position. The flow control valves were individually designed and tested to accommodate the expected flow control requirement from each lateral. The retrievable valves and the mandrels into which they are installed are designed using Side Pocket Mandrel (SPM) technology.

The installation was carried out in February 1999, with production start-up from one lateral following immediately thereafter. The well produced with an expected increased water cut until it was shut-in in September 1999. Through hydraulic cycling of the flow-control valves, the production was changed to the other lateral, producing the same volume of oil, but only a fraction of water.

With the inflow-control valves successfully operating in this well, we further optimized production, including commingled production from both laterals.

This completion set several firsts: one for the long length of its extended reach and another for the first surface-controlled flow device installed below an electric submersible pump (ESP). The team estimated that flow control would allow recovery of an additional 1 million bbl [158 900 m3] of oil that otherwise would not have been economically recoverable.
Production Experience From Smart Wells in the Oseberg Field
Authors: Erlandsen Sigurd M.
Published: December 2007

The Oseberg Field is located offshore Norway 140 km Northwest of Bergen at approximately 100m waterdepth. Including the recently installed Oseberg D gas platform, the field is developed with four offshore installations. The expected reserves estimate is 336 MSm3 of which 266 MSm3 has been produced by January 2000. Pressure maintenance is implemented by re-injection of associated gas and import of gas from the nearby Troll Field. In addition water injection takes place in some parts of the field.

Oseberg is by May 2000 producing approximately 46000 Sm3/d (290000 stb/d) from 42 production wells. Plateau oil production of 81000 Sm3/d (510000 stb/d) ended in 1997. The initial 200m oil column has been reduced to an oil rim of 20-40m as more than 75 percent of the reserves have been produced. Most producers have experienced gas break through and oil production is now limited by gas handling capacity.

The use of smart wells enables remote control of zones with excessive gas production. In the Oseberg Field, such completions have so far been installed in four wells. In the first well one ‘smart’ completion was installed in combination with mechanical sliding sleeves in two other zones. The primary objective was to verify the robustness of the equipment at downhole conditions of the Oseberg field. In the second well four zones with this completion was installed in a channel sand deposit. Rapid gas break through at the heel of the horizontal section was choked remotely, resulting in a reduced GOR and improved oil production rate. The third well with four zones was installed in a more homogenous formation. Communication was lost with three of the four zones after 40 days production. Production from the fourth well commenced in august 1999. Technical operations of the three zones were ok, but the well was experiencing production problems in the beginning due to poor pressure support and lifting problems.