bluuebunny/crossref_metadata_2025 huggingface dataset:
Design, Engineering, and Construction of Steel Catenary Risers for Indonesia Deepwater Field Applications
Authors: Korloo Jafar , Thomas David
Published: December 2007

Risers play an important role in the drilling, production, and transportation of hydrocarbons and other fluids associated with offshore oil and gas production. For a floating production system, risers provide the link between the surface facility and the subsea flowlines / pipelines that in turn link to the oil/gas wells, and to the on shore storage and export facility.

Risers are one of the most challenging aspects of deepwater projects, and also have a direct influence on the selection and design of both the floating facility and its mooring system.

There are a number of deepwater riser concepts. The most economical solution is typically Steel Catenary Risers (SCR) which are made up of welded rigid pipe sections. The main advantages of SCRs is that the steel pipe has a relatively low cost and there are relatively few other components to consider. However, the construction and long term fatigue performance of the SCRs present significant challenges to the engineer.

The environmental conditions in the deepwater areas of East Kalimantan, Kutei basin can prove suitable for the application of SCR riser concepts. The first application of SCRs in the Kutei basin is on the West Seno Floating Production Unit (FPU). This is also the world's first application of SCRs supported by a barge type floating structure.

This paper presents an overview of the application of SCRs in the Kutei basin with reference to West Seno field experience. The following areas are addressed: Design and engineering;Material selection;Welding issues, qualification of welding procedures and fatigue tests;Construction, inspection, NDE, acceptance criteria;Pre-installation, hook up and as installed configuration verification
Successful Placement of Openhole Plug in HT Conditions
Authors: Araiza Gúmaro Guzmán , Rogers Hank , Peña Lauro , Montoya Salvador
Published: December 2007

This case history paper describes the use of a bottomhole kickoff assembly (BHKA) tool to place openhole plugs in a high-temperature well. The well was a 6 ½-in. diameter borehole with 52° deviation and 174°C (345°F) bottomhole static temperature (BHST). Depth was 5775 m (18,946 ft). Even though these extreme conditions were anticipated, they were discussed with the operator because two earlier attempts to achieve a kickoff had failed.

In this successful kickoff operation, the BHKA was tagged 1 m (3.3 ft) below the calculated top of cement and was tested to 6 tons over the plug, using a 165-mm (6 1/2-in.) roller cone bit. Conditions for both the tool and cement slurry were extreme. Kickoff was successfully accomplished during the first 8 m (26 ft) of the BHKA plug; formation cuttings of 99% were reported.
Flow Assurance Challenges in Deepwater Gas Developments
Authors: Kopps Richard , Venkatesan Rama , Creek Jeff , Montesi Alberto
Published: December 2007

The Flow Assurance strategy is crucial in the early stages of development of subsea gas fields. The key questions in early development are an optimal tradeoff between managing risk effectively while ensuring deliverability and keeping CAPEX within acceptable project economic limits. The Flow Assurance plan addresses the interaction between production chemistry and multiphase flow and the resulting effects on operability, deliverability, and system performance.

This paper focuses on two key aspects of the flow assurance plan for subsea gas developments, the strategies for managing hydrates and the wax deposition. Hydrate management strategy must focus on preventing blockages versus preventing hydrate formation. To this end the engineer must evaluate flow conditions, system geometry, and production profiles, in addition to temperature and pressure conditions. In particular, a realistic water production profile during field life is needed to frame a workable hydrate management strategy. While continuous injection of thermodynamic inhibitor is the traditional solution, thermal management may be deployed effectively for certain fields, resulting in lower CAPEX and OPEX. Operability at restart must also be evaluated, focusing again on preventing blockage rather than preventing hydrate formation.

In several Indonesia deepwater gas developments, as well as elsewhere in Southeast Asia, gas condensate systems have a relatively high amount of wax (>2 w/w%). This high wax content indicates wax problems may occur during production operations. Thermal management may help solve potential deposition problems. The pour point and the wax appearance temperature indicate the potential temperature for stock tank condensate gelation and the highest temperature that the wax typically deposits. These transition temperatures can also be reduced to manageable levels through solution gas content in the produced fluid. For example, typical simulation tools forecast wax deposition with gas condensates, but these deposits are seldom realized.
Improved Interpretation of Reservoir Architecture and Fluid Contacts through the Integration of Downhole Fluid Analysis with Geochemical and Mud Gas Analyses
Authors: Dong Chengli , Elshahawi Hani , Mullins Oliver C. , Venkataramanan Lalitha , Hows Melton , McKinney Daniel , Flannery Matthew , Hashem Mohammed
Published: December 2007

Understanding reservoir architecture is critically important to effective reservoir management. Misinterpreting reservoir compartmentalization, for instance, can result in non-optimal well placement, completion strategy, and facilities design as well as large errors in reserves, drainage volume and production rate predictions. Downhole fluid analysis along with complementary techniques including geochemical, mud-gas and pressure analyses provide valuable insights into reservoir architecture. Each analytic method relies on different fluid traits and has its own limitations. With systematic integration of different methods, the synergy delivers a more accurate characterization of the reservoir.

In this paper, we link traditional and novel fluid analysis methods to build a more complete interpretation of the reservoir fluids and provide greater insight into reservoir architecture. This leads to improved understanding of structural history, hydrocarbon migration and entrapment, reservoir connectivity, and fluid contact levels. This, in turn, enables better well placement and more effective development planning. We highlight three case studies in which we have successfully combined various fluid-based techniques for improved reservoir characterization.
Completion Design for a Highly Compacting Deepwater Field
Authors: Procyk Alexander D. , Jamieson David P. , Miller Joe A. , Burton Robert C. , Hodge Richard M. , Morita Nobuo
Published: December 2007

The Magnolia field, located in the deepwater region of the Gulf of Mexico, produces oil and gas from a TLP in 4673’ of water. The reservoirs comprise several stacked sandstone intervals within the early to mid Pleistocene with some minor production from the Miocene and Pliocene sands. A total of 8 wells have been completed, with the majority of the production from the B25 sandstone. The formation particle size is fine-grained sand to coarse silt and has relatively low K*H compared to other deepwater reservoirs. The reservoirs are significantly overpressured, highly compartmentalized, highly compacting and have experienced significant pressure declines in excess of 8000 psi in some cases during production.

The wells were completed with cased hole frac packs and each completion included a permanent downhole gauge, enabling interpretation of the K*H and skin throughout the producing history of the wells to date. The perforating guns, frac fluids and screens were extensively tested prior to completion. The perforation shot size and density was carefully chosen and tested to achieve the required production. Well test results matched inflow analysis predictions. The initial skin values generally met expectations and improved during production due to a combination of well clean-up and reduced reservoir permeability from compaction. Proppant integrity has been maintained under extreme depletion (>8000 psi) conditions. Productivity was measured using perforation tunnel permeability (Kpt) analysis. The Kpt values were analyzed over the course of production and compared to similar type completions. The Kpt benchmark analysis shows that the completions are among the best in class. Well productivity has met or above expectations, and the longevity has exceeded expectations in most cases.
Peace River Carmon Creek Project—Optimization of Cyclic Steam Stimulation Through Experimental Design
Authors: Koci Paul Frantisek , Mohiddin Junaid Ghulam
Published: December 2007

Peace River Carmon Creek is a 100% Shell owned ultra-heavy oil lease located in north-western Alberta, Canada, approximately 700 km northwest of Edmonton (Fig. 1). It holds nearly eight billion barrels of 7°API oil in place, spread over 370 km2. The Carmon Creek Project targets possibly about half of that oil for development by cyclic steam stimulation (CSS). There are growth plans for a significant increase in oil production over the next five years.

The purpose of this study was to optimize CSS well configuration and steaming strategy for each distinct reservoir area by deploying previously improved and history matched simulation models1.

A full field static model was built, comprising over 400 wells. More detailed static sector models were also built for each distinct geological area and translated into elements of symmetry thermal simulation models.

The choice of design parameters and handling of uncertainties were addressed in a phased manner. First, the smallest possible element of symmetry simulation model and the most efficient discrete fracture realization were determined. The next phase involved optimization of the well configuration and steaming strategy for each field area (based on approximate Net Present Value, NPV). The final phase entailed uncertainty analysis for the optimized design concepts and determining P15, P50, and P85 forecasts for each area. Experimental Design and Monte Carlo simulations were applied to further reduce the runs required for each phase.

Although different optimum CSS designs were determined for each geological area, the modeling results can be generalized as follows:

Horizontal well near the base of the reservoir is the optimum well type for CSS at Peace River. Well spacing less than 75 meters appears more attractive in the higher reservoir quality areas compared to the current assumption of 150 meters.

In summary, a series of predictive CSS simulation models, primarily for horizontal wells, have been developed. Heavily aided by experimental design, a unique phased modeling workflow was applied to optimize well design and steaming strategy. Some of the suggested design components are already being tested at Peace River.
Beyond Decline Curves: Life-Cycle Reserves Appraisal Using an Integrated Work-Flow Process for Tight Gas Sands
Authors: Rushing J. A. , Newsham K. E. , Perego A. D. , Comisky J. T. , Blasingame T. A.
Published: December 2007

Decline curve analysis is often either the only or the primary tool used for reserve evaluations in tight gas sands. However, the flow and storage properties characteristic of low-permeability sands often preclude accurate assessments using only or primarily decline curve analysis, especially early in the productive life. The most accurate reserve estimates incorporate multiple data sources and the appropriate evaluation techniques. Therefore, this paper presents a reserves appraisal work-flow process that complements traditional decline curve analyses with comprehensive and systematic data acquisition and evaluation programs that integrate both static and dynamic data.

Our approach—which has been developed specifically to incorporate the production characteristics of tight gas sands— is an adaptive process that allows continuous but reasonable reserve adjustments over the entire field development and production life cycle. Implementing this process will prevent unrealistic (either too low or high) reserve bookings. Although it is applicable during any field development phase, our work-flow process is most beneficial during early stages before true boundary-dominated flow conditions have been reached and when reserve evaluation errors are most likely.
Innovative Method for Predicting Downhole Pressures During Frac-Pack Pumping Operations Facilitates More Successful Completions
Authors: Jannise Richard C. , Edwards William J.
Published: December 2007

Pressure limitations often prohibit engineers from placing frac-pack sand-control treatments where they are needed the most because of the collapse ratings of the bottomhole assembly equipment. Often, these pressure limitations lead to early abandonment of the well, or they create problems later in the life of the well, because they do not allow for effective sand-control, which inevitably will have a negative impact on well economics. A new method, dynamic pMAX, used to determine the amount of pressure exerted on the bottomhole tools during the sand-control treatment, enables frac-pack treatments that the industry once would have considered impossible to achieve.
An Experimental Study of Hole Cleaning Under Simulated Downhole Conditions
Authors: Yu Mengjiao , Takach Nicholas E. , Nakamura David R. , Shariff Maher M.
Published: December 2007

With increasing measured depths and horizontal displacements in extended-reach, high-angle wells, hole cleaning remains one of the major factors affecting cost, time and quality of directional, horizontal, extended reach, and multilateral oil/gas wells. This study involves experimental research and theoretical analysis to enhance cuttings transport capacity in oil and gas well drilling operations. The effects of drilling fluid rheology, mud density, temperature, borehole inclination, pipe rotation, eccentricity, rate of penetration (ROP) and flow rates were investigated experimentally. Volumetric cuttings concentration in the test section and frictional pressure losses were measured during the tests using two nuclear densitometers and a differential pressure transducer.

A total of 116 experiments were conducted on a full-scale, High-Pressure High-Temperature Flow Loop (57.4-feet long, 5.76" x 3.5" annular section) at The University of Tulsa under controlled experimental conditions (up to 200°F and 2000 psi). Experimental results show that drillpipe rotation, temperature and rheological parameters of the drilling fluids have significant effects on cuttings transport efficiency. A dimensional analysis was conducted in this study to develop correlations that can be used for field applications. A user-friendly simulator was developed based on the results of the dimensional analysis and correlations. This simulator can be used by drilling engineers for design and sensitivity study. Results from this study can be used to determine critical conditions for efficient hole cleaning, as well as to optimize the mud program during the planning and operational phases of drilling.
An Integrated Study of Low Permeability Reservoir in the Bekasap Field, Central Sumatra Basin, Indonesia
Authors: Pramudyo Yuni B. , Hendar S. M. , Nur Hasyim M. , Reinhold Mark R. , Jacobs Garry W.
Published: December 2007

An integrated geological study has been performed for a large, mature field at the Bekasap and Menggala formation. The primary goal of the study was to developed an integrated reservoir description for targeted infill drilling and improve recovery in a low-permeability reservoir. Integration of geological and petrophysical studies and reservoir performance analysis provided a rapid and effective method for developing a comprehensive reservoir description.

A 3D geocelluar model of reservoir architecture and properties distribution was made and used as a guide to further development. This model delineates distinct trends of estuarine, sand ridge, and margin facies throughout the field that reflect paleogeography. Additionally, reservoir properties and saturations were geostatistically populated within the model.

Horizontal wells were chosen as the preferred alternative to provide maximum exposure of reservoir layers and improve production and ultimate recovery compared to conventional vertical wells or frac jobs. Thirty one (31) horizontal wells were drilled in the Bekasap field, and this program was very successful and predicted ultimate recovery has improved from 14% to 28%.

The study of this low permeability reservoir in the Bekasap field is an excellent opportunity to: (1) demonstrate the economic importance of this zones, (2) understand the methodologies required for identifying and evaluating these pay types, and (3) help the company to find additional reserves in the Central Sumatra Basin.
Constant Reservoir Evaluation Through Real-Time Data as a Service
Authors: Mezzatesta A. G. , Shaw D. C. , Webb S. J.
Published: December 2007

Many sensors and devices in the field are now available to the reservoir manager for on-line surveillance and monitoring of his assets. Recently, systems typically termed "Intelligent/Smart Fields", "e-Fields" or "Fields of the Future" have begun to communicate this field data and information directly to his desk. However, the industry still finds itself faced with the challenge of transforming all this raw streaming data into useful information.

A multitude of potential applications for real-time field data has become apparent. At short periods, it is already widely used to identify anomalies and provide alarms in the classical Field Automation sense. At medium-long term, however, data ought to be used to identify well and reservoir pressure and flow signatures that help in Formation Evaluation, and for reservoir management and planning through the use of flow simulation and automated history matching.

However, rarely is data exploited effectively even at the short timeframes, and hardly ever at the medium and long term. This is largely because the analysis involved - which includes highly technical disciplines - simply cannot be automated by computer. This paper examines how our next big challenge in the Field of the Future will be the ability to streamline these engineering activities and to be able to deliver the associated analysis as a turnkey service to the Field Operator. In particular, it may be that the delivery of this key reservoir knowledge, given the current staff structure of the industry, will only be practical using a third-party service provider approach.
Development of a Coupled Geomechanics Model for a Parallel Compositional Reservoir Simulator
Authors: Pan Feng , Sepehmoori Kamy , Chin L. Y.
Published: December 2007

This paper presents a coupled geomechanics and compositional model and applies it to the oil and gas recovery process. An equation of state compositional simulator called the General Purpose Adaptive Simulator (GPAS), developed at the University of Texas at Austin, which uses a finite difference method for the solution of its governing partial differential equations (PDEs), is iteratively coupled with a geomechanics model that is developed using a finite element method in this research. An elastic constitutive model is applied to represent deformation behaviors of rocks in the geomechanics model. Porosity is selected as the coupling parameter between two coupled models. The unknowns located on nodes and block-centers in the two models are evaluated using an area weighting technique

The proposed model has been implemented on the Linux PC clusters for solving 2D compositional reservoir problems considering geomechanics effects. These results indicate that the geomechanics-coupled compositional reservoir simulator developed in this study can be used to complete simulations for stress-dependent or stress-sensitive reservoirs.
A New Azimuthal Deep-Reading Resistivity Tool for Geosteering and Advanced Formation Evaluation
Authors: Bittar M. , Klein J. , Beste R. , Hu G. , Wu M. , Pitcher J. , Golla C. , Althoff G. , Sitka M. , Minosyam V. , Paulk M.
Published: December 2007

Drilling services and oil companies have long been interested in acquiring the capability of landing a well accurately in a hydrocarbon reservoir and remaining in it for optimal drainage. Although traditional logging-while-drilling (LWD) propagation resistivity tools can help to achieve this goal, their overall effectiveness is not satisfactory because they lack azimuthal sensitivity. Ideally, geosteering and advanced formation evaluations, such as anisotropy calculations, require azimuthally sensitive measurements.

This paper discusses a newly developed propagation resistivity tool that is designed to be azimuthally sensitive for use in geosteering and formation evaluation while drilling. It uses the tilted antenna concept to produce directionally sensitive measurements that are lacking in traditional LWD propagation tools. This paper also discusses the theory and the development of this tool, as well as the experimentation and numerical modeling data used to characterize its azimuthal capability. Advanced application algorithms used to calculate the horizontal and the vertical resistivity (anisotropy calculation), as well as dipping angle will be explained in detail. Finally, the paper presents and discusses field examples to demonstrate that this newly developed tool is a two-in-one service: geosteering and advanced formation evaluation.

The azimuthal deep-reading resistivity is shown to bear the promise for use in optimization of well trajectory and well placement, as well as in advanced formation evaluation while drilling. This newly developed tool is superior to traditional propagation tools in locating bed boundaries and in keeping the well in the desired pay zone. In addition to providing traditional multi-depth of investigation resistivity measurements, this new tool provides multi-depth of investigation azimuthal resistivity measurements.
Estimation of Initial Fluid Contacts by Assimilation of Production Data with EnKF
Authors: Thulin Kristian , Li Gaoming , Aanonsen Sigurd Ivar , Reynolds Albert C.
Published: December 2007

Much recent work on automatic history matching and data assimilation has focused on the adjustment of simulator gridblock permeabilities and porosities. Here, we show that when production data are assimilated into reservoir models with the ensemble Kalman filter, it is relatively easy to account for uncertainty in the depths of the initial fluid contacts and provide estimates of these depths in addition to the traditional estimates of rock properties fields. The contact depths strongly affect the initial oil in place and cumulative oil production. We demonstrate that if one uses fixed, but incorrect fluid contacts when assimilating data with EnKF, reasonable matches of production data are obtained, but future performance predictions are inaccurate and severely biased. Considering these same inaccurate contact depths as the means of probability density functions for the two depths and including both the contact depths and rock property fields in the EnKF state vector, we obtain improved performance predictions compared with the case where incorrect depths are assumed to be correct. With uncertain initial fluid contacts, the estimates of the location (depths) of the contacts obtained by matching production data are more accurate than the prior estimates, but unfortunately, do not always provide an improved estimate of the thickness of the oil column. However, this is reflected in a larger estimated uncertainty in the predictions.

In the reservoir engineering community, there exists some uncertainty about whether performance prediction runs with a reservoir simulator should be made by predicting forward from the end of data assimilation or by rerunning the reservoir simulator from time zero using the final ensemble of reservoir parameters obtained at the final data assimilation step. We show that if the model error is negligible and the relation between data and the combined state vector is linear, then both procedures give the same predictions. We demonstrate, that for the nonlinear examples considered here the two procedures give reasonably consistent results, although rerunning from time zero tends to give slightly larger estimates of uncertainty in the predictions.
A Model for Water Injection into Frac-Packed Wells
Authors: Suri Ajay , Sharma Mukul M.
Published: December 2007

Description of the material

A model is presented for predicting the performance of water injection wells with frac-packed completions. The model estimates the plugging of the frac-pack because of solids in the injected water and its effect on the frac-pack completion. It takes into account the thermal stresses caused by cold water injection and pore pressure changes.

Application

Frac-packs are increasingly being used for sand control in injection wells in poorly consolidated reservoirs. These completions allow for large injection rates and longer injector life. Many of the large off-shore developments in the Gulf of Mexico and around the world rely on these completions for water flooding and pressure maintenance. The performance of these injectors is crucial to the economics of the project since well intervention later in the life of the field is expensive and undesirable.

Results, Observations, and Conclusions

Injector performance is shown to depend on the solids content in the injected water, proppant size in the frac-pack, initial width and length of the frac-pack, injection rate, injection water temperature and the minimum horizontal stress. In cases with wide and conductive frac-packs, the plugging of the frac-pack will be gradual and the injectivity would remain high. In cases where significant plugging may occur, a rapid rise in the bottom-hole pressure will result in sharp decline of initial injectivity. However the frac-packs will widen up after the bottom hole pressure reaches a critical pressure because of a high permeability channel through the frac-pack which will alleviate the injectivity decline.

Significant New Contributions

A model for water injection into frac-packed wells is presented for the first time. It accounts for plugging of the frac-pack and the formation around, thermal stresses caused by cold water injection and frac-pack widening and/or lengthening.
Case History: G-Function Analysis Proves Beneficial in Barnett Shale Application
Authors: Syfan Frank E. , Newman Stacy C. , Meyer Bruce R. , Behrendt Dan M.
Published: December 2007

The G-Function plot originally developed by Castillo was based on the work of Nolte's pressure decline analysis. This plot provides a graphical methodology for establishing fracture closure pressure from which the fluid efficiency, fracture geometry and leakoff coefficient could be determined. The Nolte method of pressure decline minifrac analysis using the G-Function plot has become a standard for fracture calibration in the industry from the high permeability (low efficiency) to low permeability (high efficiency) tight gas formations worldwide. Minifrac analysis has become a critical part of the fracture model calibration procedure for the successful design, evaluation, and implementation of hydraulic fracture treatments.

Although Nolte's original work has many simplifying assumptions regarding fracture closure (e.g., constant leakoff coefficient, no spurt, no fracture growth after shut-in, constant compliance, etc.), it still provides the foundation for the basic first order parameters affecting pressure decline behavior. The G-Function analysis is now routinely used as a starting point for calibrating the input data required in 3D fracture simulators.

To date, little or no information has been published supporting G-Function testing and analysis in the Barnett or other fractured shale formations. Fractured shale completions are still expanding in the Barnett and are becoming more prevalent throughout many additional geographic locations. Ultimately, completion success and the commercial viability of an asset in a tight naturally fractured shale formation, such as the Barnett, depends on an optimized hydraulic fracture stimulation using design parameters obtained through G-Function testing and analysis.

Using this fracture diagnostic technology leads to increased reserve recovery and cost effective proppant fracture treatments.
Application of 3-D Reservoir Simulator for Hydraulically Fractured Wells
Authors: Lolon E. P. , Shaoul J. R. , Mayerhofer M. J.
Published: December 2007

The evaluation of hydrocarbon reservoirs often requires a reservoir simulation model. Historically, there have been two basic approaches used for modeling a hydraulic fracture in a 3-D reservoir simulator. In the first method, the hydraulic fracture was approximated with a negative skin or an increase in the effective wellbore radius. This approach was generally adequate for moderate to high permeability wells; however, it does not capture all the important physics of flow into and through the fracture. This limitation becomes even more critical in cases of multiphase flow, multi-layer reservoir and non-Darcy effects in the fracture. In the second method, the fracture was explicitly simulated in the reservoir model. In simple cases, this approach was practical even when the gridding was performed manually. Its main limitation was the gridding schemes that represent both the fracture and reservoir becoming complicated–especially for horizontal wells with multiple hydraulic fractures and multi-layer reservoirs.

In the past few years, with advanced computer technology, it became feasible to routinely run 3-D simulations of multiphase production from multi-layer reservoirs while explicitly modeling the hydraulic fracture in a reservoir simulator. Although such a technique is not new, the latest capability reported in this paper completely automates the process of setting up the grid and initializing the grid block properties for the fracture and reservoir. It automatically transfers the fracture properties such as geometry, permeability, porosity, filtrate fluid distribution and initial pressure distribution from the fracture growth simulator into the reservoir simulator, thus making the optimization of hydraulic fracturing both easier and more realistic.

This paper reviews the advantages of 3-D numerical simulation for hydraulically fractured wells. Field examples are presented to illustrate the application of this technology for production modeling and history matching complicated reservoir cases involving fracture stimulation.
Analyzing Simultaneous Rate and Pressure Data from Permanent Downhole Gauges
Authors: Rai Himansu , Horne Roland N.
Published: December 2007

Permanent downhole gauge data provide us with reservoir information in space and time and aid in well and reservoir management. Interpretation of permanent downhole gauge data is a fairly new problem and several outstanding issues remain in this area.

This paper addresses some of the challenges in analyzing flow rate data and pressure data from permanent downhole gauges - development of improved algorithms for reliable and accurate identification of transient break points (to separate transients into relevant subsections), and investigating the impact of continuous downhole rate data in analyzing well tests.

We tested four different algorithms, one based on the stationary Harr wavelet transform method and others based on nonwavelet approaches such as Savitzky-Golay Smoothing Filters and a novel pattern recognition approach called the Segmentation Method. These four methods were developed for accurate and reliable identification of break points using both pressure and rate data.

The new methods developed in this paper were applied to real field data and the results were compared to the spline wavelet-based approach. All the nonwavelet approaches showed significant improvement over the wavelet-based method in identifying the true break points and avoiding false break points, thus reducing manual editing of break points. Also, significant difference in the estimates of permeability and skin was observed by using continuous rate information instead of average rate data for interpreting transient pressure data.

These new algorithms find their application in the interpretation of permanent downhole gauge data using conventional well test interpretation methods, to obtain dynamic information about changes in properties of the well and reservoir. The use of continuous downhole rate data can have significant advantage in well test interpretation.
Iteratively Coupled Reservoir Simulation for Multiphase Flow
Authors: Lu Bo , Alshaalan Tareq M. , Wheeler Mary F.
Published: December 2007

FIM (Fully Implicit Method) and IMPES (Implicit Pressure Explicit Saturation) are two of the most commonly used time-stepping schemes in present reservoir simulation. However, neither of them satisfies the requirements of accuracy and efficiency with increasing size and degree of complexity of highly heterogeneous reservoirs. In this paper, an iterative coupling scheme is developed and applied to multiphase reservoir problems, which aims to model and simulate realistic reservoirs accurately and efficiently.

Numerical examples reflecting major difficulties in treating heterogeneities and simulating complex reservoir phenomena such as coning and countercurrent flow problems are presented in comparison studies of iterative coupling, FIM and IMPES methods. Our results indicate that for the same accuracy the iterative approach can reduce computational time by 30%-40% or even more over the FIM. In comparing with the IMPES method, the iterative method shows better stability for taking larger time steps, and superior local mass balance. In this paper, the iterative approach is also shown to be scalable in parallel.

Another advantage of the iterative coupled approach over FIM is that different numerical schemes and even physical models can be incorporated into the algorithm thus allowing more flexibility in treating complicated problems, e.g. highly heterogeneous reservoirs with different subdomain stochastic properties.
CBM: Fracture Stimulation—An Australian Experience
Authors: McMillan D. W. , Palanyk V. S.
Published: December 2007

This paper reviews the fracture stimulation experience at the Dawson Valley CBM project situated in the Bowen Basin, Queensland, Australia. Multi stage water fracture stimulation was proven to be the most effective stimulation method. Stimulating multi-seam targets requires an aggressive fracture technique to ensure more than one seam is stimulated. Water volume, rather than sand volume, influences the Fracture Stimulation effectiveness.
Detecting Water Influx in Beam Pump Lifted Horizontal Wells in a South Oman Field Uing Temperature Measurements, Production Profiling, and Concentric Coiled Tubing
Authors: Mahrooqi Majid , Hinai Ghaliba , Kuchel Mike , Al Sakhbouri Harith
Published: December 2007

Strong bottom water drive, high matrix permeability and complex fracture and fault networks have resulted in a significant water influx problem in a South Oman field. The majority of wells produce with a water cut of at least 90% and some new wells are experiencing early water break-through. To combat this problem, swelling elastomers (SE) on wire-wrapped screen (WWS) completions have been used since early 2004 to provide reservoir segmentation behind the horizontal completion. Open hole logging and/or underbalanced drilling are used to determine where the elastomers should be placed. Reservoir segmentation allows mechanical water shut-off methods (i.e. scab liners, clads and bridge plugs) to be employed. Older wells that do not have elastomers will require chemical water shut-off treatments.

Water shut-off (WSO) will enable redirection of reservoir and artificial lift energy to oil producing zones and hence maximize oil production and ultimate oil recovery. However, before an effective WSO treatment can be applied, the location of water breakthrough, (due to coning or a conductive fracture or fault) has to be determined. Most of the wells are artificially lifted using beam pumps which represent a barrier and a great challenge to surveillance activities under dynamic conditions. Concentric coiled tubing (CCT) and a specialized jet pump or vacuum tool has been utilized to overcome this problem.

The technique combines concentric coiled tubing vacuum technology (CCTVT) with a pressure and temperature memory gauge. A procedure has been developed to utilize static and dynamic well conditions to determine water entry points: The static temperature indicates fluid migration behind the horizontal completion and gives the history of water movement from the reservoir to wellbore.The geothermal gradient is measured and compared to the static temperature – this indicates where warmer fluids are migrating from below (aquifer).The specially designed jet pump on CCT creates a localized drawdown and a steady state flowing condition.The temperature measured during the dynamic production period is compared to the static temperature to indicate the current flow of reservoir fluids.Surface sampling to measure water cut is correlated with depth to corroborate the temperature data.

This paper will present case histories of the profiling technique along with results and conclusions. It will also compare the response from this technique to normal production logging.
Simulation Studies on the Mechanisms and Performances of MEOR using Polymer Producing Microorganism Clostridium sp. TU-15A
Authors: Sugai Yuichi , Chengxie Hong , Chida Tadashi , Enomoto Heiji
Published: December 2007

Polymer-producing microorganism Clostridium sp. strain TU-15A was isolated from reservoir brine of Jilin Oilfield, China. TU-15A produces polymer in a molasses medium and increases the viscosity of the culture solution to 70cP by 10days cultivation. It's expected to be an effective microorganism for MEOR.

In this study, a simulator was developed in order to analyze the mechanisms of MEOR using polymer-producing microorganism. The numerical model in this simulator consists of 2-phases(oil and water) and 5-components(oil, water, microorganism, nutrient and polymer). This model includes almost all processes of MEOR such as growth and death of microorganism, nutrient consumption, polymer production, water viscosity increment, improvement of the flow profile in a reservoir and enhancement of oil recovery. The validity of this simulator was shown by a comparison of both results of the numerical simulation and a flooding experiment.

The quantitative change of microorganism, nutrient, polymer(water viscosity) and oil saturation were analyzed by a simulation of MEOR using polymer-producing microorganism on quarter of fivespot pattern flooding. Regarding the alteration of flow pattern in the reservoir, it was found that (1) the polymer produced by microorganism in reservoir flew into the main flow channel along the shortest way between the injection and production wells and water viscosity there increased, (2) subsequently more uniform flow profile of injected water as a postflash was established, and (3) the residual oil was mobilized to the production well. The additional oil recovery of 10% or higher was obtained at the early stage of the postflash.

Our simulator will be a first comprehensive simulator for MEOR using an existing strain that produces polymer strongly. By using this simulator, the phenomena occurred in a reservoir on MEOR using a polymer-producing microorganism have been clarified and the high performance of this MEOR process have been demonstrated.
An Update to Viscosity Correlations for Gas-Saturated Crude Oils
Authors: Bergman David F. , Sutton Robert P.
Published: December 2007

For live crude oils, dissolved gas acts to reduce viscosity from the value observed for dead oils. The reduction in viscosity can significantly impact pressure drop and flow rate and must be properly accounted for by any viscosity model. This article provides a detailed review of existing correlation methods and offers state-of-the-art solutions necessary for oil field operations in 2007 and beyond.

A total of 21 methods for calculating saturated oil viscosity have been identified from the literature. A large database consisting of data from oil PVT reports and literature sources has been compiled in order to evaluate these methods. This data represents over 12,000 measurements from 1849 samples. The gases dissolved in the oils contain varying amounts of non-hydrocarbons and the oils provide a representative crossection of the expected range in API gravity and Watson characterization factor found in crude oils from producing regions located around the world. A detailed analysis of correlation performance has been conducted which reveals inaccuracies in many of the previously published methods. As a result, a new method is proposed which is consistent across a wide range of parameters and offers increased accuracy over existing methods.
Supporting Deployment of New Technology in Developing Oil and Gas Provinces From a Centralized Support Centre
Authors: Cannon Katherine , Kay Ian , Amadi Kingsley
Published: December 2007

Industry growth is currently characterized by the migration of cutting edge technologies from regions traditionally used as the proving grounds (eg North Sea, GoM) to emerging markets such as West Africa, Russia and the Caspian.

There are many challenges to successful deployment of complicated new technologies in these areas including logistics a lack of infrastructure and access to experienced work force.

This paper aims to describe the development and implementation of a centralized support center, work processes developed to enhance local maintenance procedures, enabling technologies developed, describe successes to date and outlines potential further developments.

Recent technology introduction/ migration in Nigeria necessitated the re-tooling of the workshop, competency development of local maintenance workforce and skill development of the offshore staff.

Building on over eight years of remote operations experience a centralized support center was established at a maintenance centre in Aberdeen to support new downhole technology introduction in West Africa.

The support centre was created to enable subject matter expert's access to all facets of the technology introduction and, for what is believed to be a first for a service company; work processes and technology were developed to provide focused second line support for the workshop maintenance personnel in Port Harcourt.

New roles and work processes were developed that give local repair and maintenance staff access to dedicated expert support during critical phases of tool turnaround including strip down, component inspection and tool programming. These processes are enabled by an underlying communications infrastructure that allows portable computing devices to be utilized on the shop floor, video conferencing and network access to workshop computers.

Expertise to support rigsite operational excellence and improved rig-site workflows is facilitated by installing dedicated satellite communication systems which allow for work processes developed in North Sea Integrated Operations settings to be adapted for Nigerian conditions

Successes to date include remote training sessions of local maintenance staff in tool programming, real time remote troubleshooting at rigsites to resolve issues quickly and efficiently and multi-team collaboration during advanced rig- site operations.
Enhancing Production From Thin Oil Column Reservoirs Using Intelligent Completions
Authors: Almutairi Fajhan H. , Davies David R. , Singh Shamrendra
Published: December 2007

Intelligent completion have been proven to be an efficient reservoir management tool, with rapid deployment in various reservoirs environments, value have been established for the use of inflow control valves (ICVs) and different downhole sensors. One of the difficult environments to manage is the thin oil column reservoirs, where issues of rapid and simultaneous gas and water breakthrough affect ultimate oil recovery.

This study investigates the opportunities that intelligent completions provide for efficient oil recovery from thin oil column reservoirs. Three wells located in an offshore field were studied to show the benefit of intelligent completions in different reservoir behavior.

The study shows that using intelligent well completion can increase the total oil production from a well by controlling the gas and water production. The value is clearer in wells where the gas or water constraint is reached early in the well life, causing cessation of production. The ICV control strategy chosen illustrates how emphasis should be placed on delaying the gas/water breakthrough rather than controlling the production of unwanted fluids if choking reduces the well's deliverability. It also highlights the importance of applying conventional well design and reservoir engineering prior to the consideration of using intelligent wells.
Applications of NMR Logs and Borehole Images to the Evaluation of Laminated Deepwater Reservoirs
Authors: Claverie Michel , Hansen Steve , Daungkaew Saifon , Prickett Zane , Akinsanmi Olumide , Pillai Paul
Published: December 2007

Deepwater turbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sands vary in thickness from millimeter to meters in thickness. The reservoirs are highly permeable, but the silt and clay laminations affect the reservoir permeability in each layer, resulting in changes in the well productivity and sweep properties.

We illustrate the applications of NMR, borehole images and wireline formation testing technology in oil-base mud to evaluating the lithology, the geometry, and the net producible fraction of these reservoirs: We demonstrate that the partitioning of NMR T2 distribution is a robust method for calculating independent volumes of clay, silt and sand.We present the experimental set-up and the application of a novel method to calculate the thin sand fraction of a laminated reservoir from NMR free fluid volume. The results of this method are compared to the sand counts from a high resolution borehole image and from core images. This comparison reveals the effect of the lamination geometry on the formation evaluation.We illustrate the effects of thin silt and clay laminations on wireline formation tests, and on the productivity and flow profile of a production test. The dynamic reservoir information obtained from these measurements enables to understand the fluid flow behaviour and potential productivity in such a reservoir.

These techniques reduce the uncertainty of hydrocarbon volume and productivity computations in a highly laminated deepwater reservoir. The field example used in this paper is a turbidite sand from North West Borneo. The techniques demonstrated here are also applicable to the analysis of other categories of thinly bedded, shaly sand reservoirs.
Integration of Production Data Analysis Results into Geostatistical Models by Downscaling
Authors: Archer Rosalind
Published: December 2007

Production data analysis offers mechanisms to estimate permeability values (for well drainage areas) from production data. These data are valuable and readily obtained from routinely measured data. For use in geostatistical modeling however a downscaling process is required because of the volume of support production data derived permeability values have. A workflow is proposed for the integration of production data into geostatistical modeling which creates a kriged 2D map of reservoir permeability by treating production data derived permeability values as point data. The permeability values in this map are in turn used as collocated secondary data in a cokriging process used in a sequential Gaussian simulation. Numerical experiments demonstrate that the use of this workflow can substantially improve the quality of realizations from the resulting 3D permeability model.