bluuebunny/crossref_metadata_2025 huggingface dataset:
Cleaning Effectivity of Concentric Coiled Tubing in Horizontal Wells, Cerro Negro Area, Carabobo Field, Venezuela
Authors: Benzaquen I. , Romero J. , Zambrano J. , Henao P. , Ortiz A.
Published: December 2007

The Orinoco Oil Belt is the largest heavy oil accumulation in the world with 1.2 trillion of in situ reserves in an area of 54.000 square kilometers covering the southern portions of three states in the Eastern Venezuela Basin. Carabobo is one of its more prospectives areas with very thick sands with excellent petrophysical properties. The study area has 120 square kilometers corresponding to the Extraheavy Oil Unit of the Morichal District, Monagas State. In the early 80s explotation began in this area with drilling of 150-300 meters spaced vertical wells. Further secondary recovery method (including alternate vapor injection) evaluations were conducted in order to enhance a more commercial production. In late 80s and early 90s the new uprising drilling technology was used in the area, with 400 meters spaced deviated and inclined wells where further alternate vapor injection was applied. In the late 90s and 2000s drilling campaigns of horizontal wells and multilateral wells, respectively, were performed in the study area, with very dense drilling of heavy and extra-heavy oil sand reservoirs with horizontal wells of extended section that generated a very problematic large sand production. Thus, reaconditioning and cleaning up of these wells was needed in order to optimize oil and sand production within desired levels avoiding the damage of equipments after completion. Cleaning up of horizontal wells gets difficult due to circulation loss, high permeabilities and low reservoir pressure; therefore use of the 2 3/8" tail tubing was substituted by the new Concentric Coiled Tubing (CCT) technology and a Vacuum pump. CCT was tested in selected wells where it was used; evaluating parameters such as oil sand petrophysics, production behavior, cleaning up services conditions and associated costs during productive life of wells. The main results of using CCT are prolonging recurrent sanding that implies short term recurrent cleaning up services, avoiding additional expenses in repair services, equipment replacements or well closure among other disadvantages. Repair services result in money waste, disturbance of routine operational field activities and subsequent costs increase of produced barrel due to restrictions in production. Economic indicators have shown evident rentability of using this tool in horizontal wells of Extraheavy Oil Unit of Morichal District.
Production Diagnostics and Water Control for the XJG Fields, South China Sea
Authors: Jiang Zhizhuang , Tao Zhang , Kin Khong Chee , North Robert
Published: December 2007

The China National Offshore Oil Corporation (CNOOC), Shell, and ConocoPhillips China, Inc., (COPC) are partners in the development of the XJG oil fields in the South China Sea. The XJG fields are in a mature production phase and challenge COPC (the field operator) with surface fluid handling capacity issues as a result of high water cuts. Additionally, there are no more slots available in the existing platforms for infill drilling.

Typical completions include sand-control devices such as gravel packs and fracture packs inside 9 5/8-in casing with zones separated by packers and produced commingled through sliding sleeve doors (SSDs). In the past few years, more and more horizontal wells have been drilled and completed with expandable sand screens and premium screens. Most of the wells produce 10,000 to 15,000 BFPD using electrical submersible pumps (ESPs).

In these commingled completions, the water cut rises from a few percent to 80% to 90% within the first 2 years of production. Typically, sidetracks are drilled before water cut reaches 96%, using the existing producing well slots. Production logs (PL) are routinely run to evaluate zonal fluid production for reservoir management and to screen for suitable candidates to perform water control operations during ESP changeout, workover operations.

Quantitative PL evaluation in these deviated, high-flow rates, high-water-cut environments is challenging because of the uncertainty and inaccuracy of fluid holdup data acquired with conventional technology. Recently, PL data acquired with local probe holdup sensors have successfully diagnosed well production and provided guidance for workover operations to reduce water cuts and provide substantial incremental oil production. Additionally, caliper data associated with the local probe sensors is used to gauge completion diameter and to help verify perforation depth.

Performing production logging in this challenging environment requires detailed prejob planning and careful job execution. Several cases of diagnostic evaluations and different water control operations performed are discussed in this paper.
Direct Measurements of Minimum Horizontal Stress, Permeability, and Permeability Anisotropy in a Siberian Oil Field Using a Wireline Formation Tester
Authors: Ayan C. , Achourov V. , Alpatov A. , Diyashev I.
Published: December 2007

Waterflood management requires the optimization of hydraulic fracture placement. The lack of direct stress measurements (vertical distribution and direction) in the South Priobskoe field in western Siberia has created the need to determine the orientation and magnitude of the least principal stress. The presence of impermeable shales between producing sands complicates fracturing design and field development to maximize recovery. Permeability and permeability anisotropy at different depths are unknown variables that affect well completion and reservoir management decisions.

A set of wireline formation evaluation tools were used for microfracturing (stress tests) at several sand and shale formations. The stress tests were performed by isolating 1 m of formation using the dual packer module of the wireline formation tester (WFT) and creating a hydraulic fracture by injecting drilling fluid using the downhole pump. Combination of the wireline dual packer and standard probe modules provided estimates of permeability and permeability anisotropy in sands. Formation microimagery data were used before and after stress tests to obtain information on least-principal-stress direction.

Challenges created by the harsh working environments in western Siberia were addressed by detailed risk assessment, job planning, and real-time quality control and decision-making.

The use of the acquired stress and permeability data to optimize the number of wells, well patterns, selection of water injectors, and fracture design is discussed.
A Technique for Measuring Permeability Anisotropy and Recovering PVT Samples in a Heavy Oil Reservoir in North West Siberia
Authors: Achourov V. , Khamitov I. , Yatsenko V.
Published: December 2007

Wireline formation testers provide the measurements for the determination of formation pressure gradient, in-situ effective oil mobility profile, in-situ downhole fluids analysis (DFA) as well as taken PVT samples and maintaining them in single phase condition for lab analysis, interval pressure transient testing (IPTT) for characterizing of permeability anisotropy and in-situ minimum horizontal stress estimations.

Pressure and fluid samples are obtained by setting a rubber packer and small diameter probe. The packer hydraulically isolates a small part of the formation from the hydrostatic pressure, while the probe enables communication between the tool and formation. This conventional technique is well suited for thick and permeable formations. However, for difficult conditions such as laminated formations or formations with low matrix permeability and formations saturated with high viscosity fluids or fractured limestones, application of a single probe technique is limited. Under these conditions, the small packer may not be able to isolate the zone, may miss a thin zone or in a formation with very low permeability and/or high fluid viscosity the contact area with the packer may be too small to let the fluid flow. To help overcome this, technique of Wireline Formation Tester (WFT) with dual packer module is used. This wireline conveyed straddle packer has the capability of hydraulically isolating a minimum of one meter of formation. The dual packer can be set repeatedly at different locations on a single trip in the well. Using these modules, pressures, real-time formation fluid identification, PVT samples, permeability and flow rate estimations can all be evaluated in detail.

Within the vast Russian oil and gas fields environment with different geology, and wellbore and fluids conditions, the technique of combining probe and dual packer modules in one string and running the tool on TLC (tough logging conditions) has been applied successfully to a thinly reservoirs, formations with low permeability and unconsolidated formations saturated by high viscosity fluids (heavy oils).

In this paper, application of interval pressure transient testing done during formation fluid cleaning up from mud filtrate and during downhole fluid identification is described. The main objective of using the formation tester was to take downhole representative PVT samples of high viscosity fluid in a high invasion wellbore environment in three exploration wells of a new remote field. Use of dual packer for PVT sampling and single probe and vertical observation probe together provided possibility to estimate permeability anisotropy, in spite of difficult and challenging acquisition (operations were done from Geophisika Logging unit due to the field remoteness) and wellbore conditions (well bore stability and high mud filtrate invasion).
Hydraulic Fracture Diagnostics Used To Optimize Development in the Jonah Field
Authors: Wolhart S. L. , Harting T. A. , Dahlem J. E. , Young T. J. , Mayerhofer M. J. , Lolon E. P.
Published: December 2007

This paper reports on a study conducted to assist with field development in the Jonah Field in Wyoming. Microseismic and surface tiltmeter fracture mapping was performed on ten wells in two areas of the field and over 100 fracture treatments were mapped. The fracture mapping study was performed as part of a pilot project to evaluate ten-acre well spacing.

The Jonah Field is located in the Green River Basin in Sublette County, WY. Production is primarily from overpressured and tight sandstones of the Lance Formation. The Lance in Jonah consists of many stacked low permeability sandstones. Due to the low permeability, stimulation is required for economical production rates. Gross pay intervals vary from 2,800 ft to 3,600 ft and wells are stimulated in multiple fracture stages. Each fracture stage may target three to six sands with eight to twelve total stages for each well.

The study shows mapping results for fracture treatments in both mapping areas. Fracture length was longer than expected and varied somewhat by stage. Some stages were contained but for many stages there was significant height growth and treatment overlap. Fracture complexity was observed which could be due to natural fracturing, faulting, depositional heterogeneity and depletion.

These fracture mapping results are being combined with geologic, geophysical and engineering data from the field to assist with field development. This paper details the results of the mapping and discusses issues with well placement, stimulation design and treatment staging identified by the study.
A Useful Desktop Surveillance Tool For Fluid Production Prediction and Monitoring in Single and Dual Zone Completed Wells
Authors: Sorokin Alexander , Smith Scott
Published: December 2007

A useful spreadsheet based production prediction and surveillance program has been developed at the Vanyoganneft JV in Nizhnevartovsk, Russia. This paper will describe the program which will demonstrate application of fundamental petroleum engineering principles in a very practical, real time and hands on manner. As a result of this tool, real time reservoir management decisions are made, including production improvement opportunities.
Salt Free: A Case History of a Chemical Application To Inhibit Salt Formation in a North African Field
Authors: Szymczak Steve , Perkins Randy , McBryde Mark , El-Sedawy Mohamed
Published: December 2007

High salt concentrations in wells cause the precipitation of salt in the well bore. Fresh water washes dissolve the salt. Water washing has a high cost due to lost production and frequency of washes. This paper discusses the advantages of applying salt inhibition chemistry to extend the production period and increase the well economics.

Chemical technology has been introduced as an alternative to dissolution with water. Specialty polymers that exhibit super-saturation and crystal modification properties can be introduced into the well bore, preferably by a formation squeeze. Whereas the fresh water clean outs for these wells lasted no more than a week the salt squeezes lasted in excess of fifteen weeks.

The operator washed the wells for salt with fresh water on a weekly basis. Often the production had dropped prior to the scheduled wash out. After approving the chemical squeeze the wells were cleaned following a prescribed protocol. The wells were squeezed with chemical commensurate with the water production of the well. The well production was monitored and recorded. In all cases production exceeded the time seen with a water wash. At least one well has produced at the desired high rate for over one hundred days.

This paper details the design, application and results of a multiple well treatment of salt inhibitor in a North Africa field. The application of this chemical technology advances industry technology in two manners. First, it eliminates the need and cost of frequent water washes. Secondly, it increases production by extending the period of desired production and reducing the frequent production decreases brought about by the sale deposition. Furthermore the success of this technology is leading the research to develop longer lasting molecules that can be placed in both fracturing and squeeze applications.
Development of an Integrated Solution for Perforation, Production, and Reservoir Evaluation
Authors: Jaua J. , Rivas O. , Mejías A.
Published: December 2007

As a result of the increasing emphasis on reducing operating costs and minimizing deferred production, a new system was designed for perforating wells lifted with electrical submersible pumps (ESPs). The purpose of this project was to develop and apply a new concept for well completion involving ESP systems, tubing-conveyed perforating (TCP), drillstem testing (DST), and chemical treatment of the formation by using standard equipment and techniques. The concept was developed after identifying the opportunity to optimize operations in wells where the above equipment and operations are required.

This paper summarizes practical experience gained during the development and deployment of this system.
Time and Depth Migrations Over Giant Lunskoye Gas Field, Offshore Sakhalin Island, Russian Federation
Authors: King K. , Jackson P. , Haneveld C. , Veeken J. V. D. , Kremers N. , Dunne J. , Molen M. V. D. , Ross L. , Bodewitz G. , Stone G. , Meij R.
Published: December 2007

Sakhalin Energy Investment Company Ltd. (SEIC) acquired a new 3D seismic survey over the giant Lunskoye gas field in 2003, orthogonal to the 1997 N-S 3D survey. The survey was acquired within time and budget, with an extensive environmental program to ensure minimal impact. The new survey attempted to undershoot the gas cloud, which extends N-S along the Lunskoye crestal axis. A high-quality, Shell-processed, prestack time migration (PSTM) volume was produced and interpreted followed by two prestack depth migration (PSDM) volumes. The first PSDM, in 2005, extended to just below the penetrated reservoir depth interval and used a velocity field without an interpreted low-velocity gas ‘body’. The second PSDM, in 2006, was extended in depth and migrated with an interpreted shallow gas body in the velocity model.

The structure and structural uncertainties derived from the 2005 PSDM were used in the SEIC's Integrated Reservoir Model (IRM) project. Structural uncertainty was constrained by data from all seven wells and through the integration of seismic amplitude information and fluid contacts derived from petrophysical data. Three discrete structural cases - low, reference and high – were interpreted which honored these constraints.

A number of comparisons were made between the 1997 and 2005- 2006 orthogonal depth migrations. Quality of seismic reflectivity over the crest improved dramatically. Faulting outside the gas cloud area has remained fairly consistent between the datasets. Time-to-depth conversion will be discussed and differences in migration velocity models also presented.

Reliable reservoir models depend, to a large degree, on the quality of seismic data used in seismic inversion. In an area where a severe gas cloud obscures proper reservoir imaging, all improvements to the structural and stratigraphic image will have a positive impact on the reservoir model.
Limited Entry Perforations in HVO Recovery: Injection and Production in Horizontal Wells
Authors: Burtsev A. , Kuvshinov B. , de Rouffignac E. , Mollinger A. M.
Published: December 2007

This paper presents an assessment of the performance of a horizontal well, completed by limited-entry perforation (LEP) technique, based on reservoir and well simulation of a typical HVO reservoir, e.g., Peace River field and theoretical calculations. The issues that are primarily covered in the LEP simulation work address the comparison of horizontal LEP injector with conventionally perforated liner for a generic reservoir; the role of the sand-screen in LEP design during HVO production and the analysis of the pressure drops through the LEP hardware.

Modelling of the injection scenario with LEP's has shown that in high permeability contrast reservoirs at critical flow conditions, perforations located in zones with permeability variation between 10,000 and 1,000 mD, have the same maximum injection rate. If the wells from Peace River perform similar to the Imperial D–36 HWCSS LEP wells from Cold Lake, then the expected gross production performance that these wells will have under LEP conditions will be around 16 m3/day per perforation. These results are in line with the production performance observed in pad D–36 and also in line with our simulations. The calculations performed here do not take into account any skin damage effects that potentially could occur when LEP's are applied in the field.

Calculated total pressure drops across the LEP hardware have shown that the liquid flow is limited by the ability of the reservoir to deliver the necessary amount of fluid to the LEP. The simulation results show that for a steam injection flow rate of 42 m3/day per perforation the expected net oil production rate of the LEP with a sand-screen in Peace River reservoir is around 4.8 m3/day/perf.

Overall it can be concluded that injection through LEP's is feasible and production through LEP's in their current configuration is possible if the formation properties are similar to Cold Lake. Potential adverse impact of skin damage under Peace River conditions could invalidate our conclusions; this should be confirmed by the testing of LEPs in the field.
Fills Cleanout With Coiled Tubing in the Reverse Circulation Mode
Authors: Li J. , Luft B.
Published: December 2007

Removing sand fills from wellbores is one of the major applications for coiled tubing (CT). For the fills cleanout process, the fluid could be circulated in two different modes: forward circulation and reverse circulation. In the forward circulation mode, the carrying fluids are pumped through the CT down to bottom and flowed back to surface in the CT/casing annulus. For reverse circulation, fluids are pumped down the CT/casing annulus and back up the coil. In many cases with large completions and low reservoir pressures, the forward circulation mode cannot effectively clean the fills out of the annulus with only a limited available flow rate or without circulating expensive gel fluids, especially for the heavier particulates in deep and/or highly deviated wells. Due to the smaller flow areas and therefore higher velocities, fills may be more readily transported inside the CT flow channel. Therefore, reverse circulation may be an option to overcome the above constraints associated with forward circulation.

Several major risks for reverse circulation with CT include coil collapse, loss of well control and sand bridging in the coil. Controlling the rate of penetration (ROP) of the CT into the fill is very critical for the reverse circulation sand cleanout process. There is a lack of knowledge on the effect of as well as optimum ROP during reverse circulation. In this paper, the maximum ROP for different sand types at different deviated angles and water flowrates for reverse circulation cleanouts are investigated with a full scale flow loop test facility. Based on these test results, empirical correlations have been developed and incorporated into an existing proprietary solids transport computer algorithm, which can now be used to optimize the hole cleaning process for both the forward and reverse circulation modes of solids transport.
Horizontal Well Performance Evaluation and Well Test Analysis – A Case Study
Authors: Sheng J. J.
Published: December 2007

Analysis based on analytical solutions dominates in conventional well testing analysis. Analytical solutions, however, meet their challenges under some complex test conditions. This paper presents a case study of horizontal well testing analysis and performance evaluation using simulation approach. In this case study, we show an example that the horizontal well tests could not be analyzed using conventional well testing methods, but they could be analyzed using simulation approach (a single well model in this case). By history matching the well tests, we calibrated the single well model. Then using the calibrated model, we evaluated the horizontal well performance. In evaluating horizontal well performance, we first analyzed the actual well performance and then investigated several factors which could affect a horizontal well performance. We also used the single well model to design a new drawdown test. The new drawdown test was successfully conducted and analyzed using an analytical model. The analysis results are consistent with those obtained from the earlier tests analyzed using simulation approach.
Near-Wellbore Stress Analysis and Wellbore Strengthening for Drilling Depleted Formations
Authors: Wang Hong (Max) , Towler Brian F. , Soliman M. Y.
Published: December 2007

Alhough lost circulation has provided a challenge for drilling, especially for drilling depleted formations, its mechanism has not been well studied or fully understood. Aided by analytical and numerical solutions, this paper identifies the role of hydraulically conductive cracks in low near wellbore pressure containment. It also demonstrates that the lost circulation frequently encountered when drilling depleted formations occurs when both near wellbore pressure containment and far field pressure containment are low.

The numerical method is used to investigate the improvement of wellbore pressure containment by propping fractures with particulate lost circulation materials to strengthen the wellbore. The results demonstrate that the wellbore pressure containment can be improved to a level beyond that of the ideal wellbore pressure containment defined by the Kirsch's tangential stress equation.
Inhibition and Removal of Low-pH Fluid-Induced Asphaltic Sludge Fouling of Formations in Oil and Gas Wells
Authors: Barker Kenneth M. , Newberry Michael E.
Published: December 2007

Many low pH fluids are used in the Petroleum Industry to treat oil and gas wells. These enclude acid fracs, pickling acid, near wellbore acid jobs and scale inhibitor squeeze chemicals. All of these fluids can cause asphaltic sludge (rigid film emulsion) in some wells that can reduce production of oil and gas, plug a well or oil wet the near wellbore formation by reacting with the asphaltenes or asphaltic resins in an oil. This paper will provide information on how low pH fluids react with asphaltenes or asphaltic resins in oil, explain why the standard test results may be inaccurate in predicting these reactions and present a non-standard method which has been used for a number of years to stop the formation of asphaltic sludge in any well at any iron concentration. Case histories of removal treatment of asphaltic sludge from wells and inhibition treatment will be presented.
Real-Time Interpretation Technology for New Multi-Laterolog Array Logging Tool
Authors: Frenkel Michael A.
Published: December 2007

Real-time array resistivity data interpretation is normally performed by means of 1D radial inversion. Such an approach may lead to errors in thin formations and cause productive zones to be overlooked. In this paper, we propose a novel real-time 2D interpretation technology developed for the new Multi-Laterolog instrument. The technology is based on a new method called Localized Rapid Inversion (LRI). LRI substantially reduces computing time by partitioning the 2D inverse problem into a sequence of 1D problems. In addition, it allows for simultaneous data correction for borehole, invasion, and shoulder-bed effects in the close vicinity of a logging point. This interpretation process is able to run in real-time by relying on a set of pre-calculated look-up tables of tool responses and a hands-off LRI-based interpretation procedure.

The technology is general and applicable to different array resistivity logging instruments. We test it on two complex benchmark models and a case study based on test field data acquired by the Multi-Laterolog tool in Odessa (West Texas). Synthetic and field examples demonstrate the capability of the technology to deliver in real-time high quality results now achievable only with the interpretation capabilities of a log analysis center.
Saving Rig Time and Providing Flawless Execution Utilizing Through-Tubing Milling Intervention With Advancements in Job Planning Guidelines and Technology
Authors: Garfield Garry , Kelbie Graeme
Published: December 2007

Many factors need to be considered when planning a well intervention. In terms of saving rig time and successful downhole milling operations, one critical success factor of milling operations is structured pre-and post-job guidelines. The guidelines may include a structured pre-job information questionnaire, which provides a more accurate picture of the problem and allows for a more detailed and auditable fit-for-purpose solution to the problem in terms of equipment selection, job procedures, and well programming. Without a set of stringent guidelines to assist in detailing the correct tools required for each application, the success of each intervention may not be realized. Through case histories this paper will show that utilizing, appropriate technology, tool designs, and structured guidelines lead to successful through-tubing intervention milling operations in cases when removing multiple composite bridge plugs. Discussion will involve the pertinent information required prior to equipment selection and job engineering and how that information relates to the equipment's performance and overall success or failure of the objectives for the intervention.
Water Shut Off: The Through-Tubing Inflatable Solution
Authors: Kelbie Graeme M. , Garfield Garry L.
Published: December 2007

With continual increase in water production from maturing reservoirs comes the expense of installation of surface handling equipment, disposal and environmental concerns and a reduction in production efficiency from hydrocarbon producing wells. These costs run into millions of dollars every year, dealing with this problem. The operators of these wells have utilized differing technologies and procedures in efforts to control production of these unwanted fluids. Water shut-off applications in one way or another are an everyday part of well servicing work. Some of the methods and practices currently used today to help combat this problem include, placement of cements, plugging back the zone with the aid of mechanical isolation devices, pulling the completion and performing work-overs, and the utilization of purposely designed cements or chemical water blocking agents. Initial efforts to utilize such fluids proved encouraging but methods were required by the operators in order to allow accurate placement of these chemicals. Some of the drivers are;

Economics, in terms of the relatively high cost of such fluids and; The reaction of such water blocking chemicals when placed incorrectly within producing formations and the inability to reverse engineer such misplacements.

Couple these problems with the well geometry to be worked in and the solution of placement can be seen to involve many diverse complications. For this reason the requirement for innovative through-tubing zonal isolation solutions has never been greater. Through-tubing inflatable technology has, for some time now, been providing high-expansion devices in order to provide our industry with an economical and reliable method of isolating and placing water blocking treatment fluids. In this paper we will focus on current inflatable tools that are available today and how they can be utilized to provide cost effective water shut-off solutions at the source of the problem.
Guidelines and Technology for Through-Tubing Milling Intervention That Provide Flawless Execution and Rig Cost Savings
Authors: Garfield G. , Kelbie G. , Wilson S. B.
Published: December 2007

When planning a well intervention, there are many factors that need to be taken into consideration prior to the execution of the operation. Designed guidelines are critical to the success of the milling operations in terms of saving rig time and successful downhole milling operations. These guidelines should include a structured pre-job information questionnaire, provide a more accurate picture of the problem, and also allow for a more detailed and auditable fit-for-purpose solution to the problem in terms of equipment selection, job procedures, and well programming. However without a set of stringent guidelines to assist in detailing the correct tools required for each application, the success of each intervention may not be realized. Through case histories this paper will show that utilizing structured guidelines, appropriate technology and tool designs lead to successful through-tubing intervention milling operations in cases when removing multiple composite bridge plugs. Discussion will involve the pertinent information required prior to equipment selection and job engineering and how that information relates to the equipment’s performance and overall success or failure of the objectives of the intervention.
Well Engineers Deserve a Seat at the Exploration Table: "The Role of Mechanical Earth Modeling in the Early Exploration Process"
Authors: Goodman H. E.
Published: December 2007

Consideration of the full cycle asset development plan from appraisal through abandonment reduces the risk of missed future opportunities due to well systems design constraints. For example, reservoir pressure depletion and subsidence can impact borehole stability to the extent that complex well designs are necessary to fully exploit the asset. Well placement not only depends on the subsiding reservoir section, but also on the reaction of the overlying geological section that must be drilled through to reach the reservoir. For land based operations, the consequences of well complexity may be more easily addressed, the downside being a poor estimate of field recovery that can either rob opportunities for outlying prospects or, in the worst case, cause the asset to be uneconomic. For major capital projects (MCPs) such as deepwater subsalt fields, the capital outlays are immense, with single wells costing up to $100,000,000. For these deepwater MCPs, fewer wells are required to produce reliably for longer periods of time.

The capability to characterize rock mechanical properties from the standard P-wave acoustic data sets, either seismic or open hole log derived, enables well planners to link the Explorationist and Well Engineer’s visions using mechanical earth modeling technology. The accurate assessment of formation rheology, or stiffness, and architecture (distribution and structure), allows the asset team to optimize well systems design, considering placement and production management practices over time.

The presentation will introduce acoustics based rock mechanics concepts, describe the acoustics based rock property prediction technique, and present field applications that demonstrate the impact of the subsurface model to the corresponding well systems design.
A Field Study Optimizing Completion Strategies for Fracture Initiation in Barnett Shale Horizontal Wells
Authors: Ketter A. A. , Daniels J. L. , Heinze J. R. , Waters G.
Published: December 2007

The Barnett shale is an unconventional gas reservoir that is currently estimated to extend over 54,000 square miles. In an effort to improve well economics and to reduce the number of surface locations in populated areas, there has been a rapid increase in the number of horizontal wells being drilled and completed. With this change in development strategy, operators and service companies alike have had to search for innovative solutions to overcome challenges faced in horizontal completions.

Inefficient fracture initiation is the largest reoccurring problem seen when completing horizontal Barnett shale wells. These difficulties are manifested as high fracture initiation and propagation pressures, which lead to low injection rates and high treating pressures. These losses reduce the efficiency of proppant placement and stimulation. As drilling activity has increased over the past couple of years, fracture initiation problems have represented a substantial source of expense and downtime.

This field study examines 256 horizontal Barnett shale wells in an effort to identify the causes of these near-wellbore issues and to offer corrective solutions for future completions. The goal of this study is to recommend an optimized completion strategy to minimize these near-wellbore problems, increase stimulation coverage and decrease unplanned completion expenses.

In 2005, 19% of the stages in horizontal wells examined encountered near-wellbore difficulties. This field study inspects the major contributors to fracture initiation, specifically focusing on cemented versus uncemented laterals, horizontal stress anisotropy, perforation strategy, cementing strategy and stimulation design.

The paper offers statistics on which changes have had the greatest effect on stimulation placement. These problems can cost operators upwards of an additional 25% per stage. Using these optimized strategies has reduced the number of stages where fracture initiation difficulties have been encountered by 74%.
A Straight Line p/z Plot is Possible in Waterdrive Gas Reservoirs
Authors: Elahmady M. , Wattenbarger R. A.
Published: December 2007

Field data and simulated models have revealed that in some cases waterdrive gas reservoirs can be mistakenly misidentified using material balance methods as depletion drive gas reservoirs causing a significant overestimation in gas reserves.

The famous straight-line plot of p/z vs. Gp has been traditionally used to estimate original gas in place (and gas reserves) for depletion-drive gas reservoirs. A gas reservoir in contact with an aquifer in transient phase (unsteady-state) and producing under a certain production schedule can plot as a straight-line on a p/z plot masking the existence of an active aquifer and causing a significant overestimation in gas reserves.

The authors in this paper simulate synthetic cases of gas reservoir/aquifer models using a forward model and an inverse model that were programmed in visual basic to show that the combination of certain rate schedules and the unsteady state nature of aquifers can cause a straight-line p/z plot in waterdrive gas reservoirs.

The authors also demonstrate that the Havlena-Odeh1,2 Plot (also known by some authors in the liteariture as the Cole3 Plot) for those same cases will also mask the existence of an active transient aquifer giving the same value of overestimated origianal gas in place (OGIP) as that obtained from the p/z plot.
Permeability Vertical-to-Horizontal Anisotropy in Indonesian Oil and Gas Reservoirs: A General Review
Authors: Widarsono B. , Muladi A. , Jaya I.
Published: December 2007

Reservoir rock heterogeneity is an ever-present occurence in most reservoirs. One among reservoir properties that are the most affected by its presence is permeability. In most cases, reservoir rock heterogeneity causes permeability anisotropy or variations in permeability with directions. As most theoretical bases used in many aspects in petroleum engineering (e.g. waterflooding, well completion, well productivity, well stimulation, and reservoir simulation) are developed under an assumption of homogeneous reservoir rocks, this permeability anisotropy certainly imposes a special problem that needs to be dealt with.

Indonesia's geological setting is characterized by its high level of complexity. Permeability anisotropy in Indonesian reservoirs varies very widely, and careless approach in picking values representing the level of heterogeneity for individual reservoir may lead to various problems. This paper presents results of a study on permeability anisotropy - in this case vertical-to-horizontal anisotropy - in Indonesian reservoirs through the use of core analysis results. The study involves 14,634 core samples, of which 6,689 are pairs of vertical and horizontal plug samples and 1,256 are full-diameter core samples. They are taken from 259 wells representing 157 fields in all 15 Indonesia's productive sedimentary basins to date. The core samples cover a wide lithology spectrum from sandstones to various limestones.

The study that is carried out through a series of classifications and comparisons has indeed shown the complexity as expected, even though differences can still be distinguished among groups of classification. Evidence has also been observed that results for sandstones and limestone/carbonates core samples as two lithology groups are significantly different even though there are also differences among either group. One very important lesson that can also be drawn from this study is a reconfirmation upon the common opinion suggesting the requirement of a careful study for individual reservoir before adopting KV/KH values for the reservoir of interest.
Smart Fields—Making the Most of our Assets
Authors: de Best Leo , van den Berg Frans
Published: December 2007

Intelligent wells and Smart Fields concept have recently been applied in some assets Shell as a solution to increase production, reduce deferment and increase recovery. Smart Field can however only be fully utilized if the three main elements fully integrate, technology, process and resources.

However Smart Fields is not only about automation. It is about making available the three key ingredients needed to efficiently operate any piece of equipment: reliable performance data, an integrated suite of tools to turn these data to information and operational advisories and a cadre of appropriately skilled professionals that use the information to make the right decisions.
Chayvo Field, Sakhalin Island, Russia: Identification of a Significant Oil Leg from 3D Seismic and Execution of a World Class Extended Reach Drilling Program
Authors: Apotria Ted G. , Mathis Randall S. , Powell Richard J. , Venner Bridget A.
Published: December 2007

In 1997, the ExxonMobil operated Sakhalin I Consortium acquired a 3D seismic survey over Chayvo Field, located off the northeast coast of Sakhalin Island, Russia. At the time of the acquisition, Chayvo was thought to contain primarily gas given the results of five pre-existing crestal wells. Interpretation of 3D seismic revealed seismic amplitude anomalies that conformed to structural spill, were down dip of gas accumulations seen in crestal wells, and indicated the potential for very large, previously unrecognized oil rims. Based on the 3D seismic interpretation, an appraisal well was drilled in 2000 that penetrated several large oil legs. This appraisal well and associated sequence stratigraphic studies resulted in a significant oil project in a field previously thought to be mostly gas.

When the oil rims were confirmed, the challenge was how to develop the Chayvo field lying 8 to 10 kilometers offshore. Development drilling at the field began in 2003, with the first phase comprising a series of extended reach wells drilled from an onshore location reaching offshore to the western limb of the Chayvo anticline. These wells are technically complex and very expensive, but attractive considering offshore platform costs in a remote, environmentally sensitive location characterized by seismic activity and pack ice in the winter.

In 2002, a multi-disciplinary team was assembled to address the challenges associated with designing and executing extended reach wells in stacked deltaic reservoirs comprised of prograding clinoforms. The primary geological concern was the accuracy with which the horizontal well bores could be placed within the oil column, as reservoir simulation indicated the need to be within 10 m of a specified vertical depth. Ongoing drilling has proven to be successful with actual reservoir depths within a few meters of prognosed depths at well reaches of 9-11 kilometers, underscoring the value in the integration of seismic interpretation and extended-reach well planning in a 3D visualization environment.
Pushing the Envelope for Production Logging in Extended Reach Horizontal Wells in Chayvo Field, Sakhalin, Russia-New Conveyance and Flow Profiling Approach
Authors: Fitz D. E. , Guzmán-Garcia Angel , Sunder Ram , Billingham Matt , Smolensky Vitaly
Published: December 2007

Production logging and flow profile interpretations are necessary to properly assess completion performance and interpret pressure buildup data in Chayvo Field. With a lateral reach in excess of 8 km, acquiring production logging data is difficult. Memory logging, with conventional production logging tools via coiled tubing and a hydraulic tractor, was employed. However, due to the wear experienced by the coil, high cost, and poor data quality at low flow rates, this technique was abandoned after initial logging efforts.

Development of a state-of-the-art electrically powered tractor, combined with new surface read out array mini-spinners and optical gas and array resistivity water holdup sensors, provided a viable logging alternative with a 40,000 ft cable specifically manufactured to avoid splice induced weakness. This new logging technology detects and measures stratified flow and lower flow rate fluid entry than conventional axial symmetric production logging tools in ERD well bores. The equipment has recorded production logs to a measured depth of 9,775 m at a true vertical depth of 2,613 m.

Comparison of cumulative flow rates from the array mini-spinner analysis to the logging-while-drilling derived cumulative permeability-thickness product has enabled the evaluation of the completion methodology. Based on the production log analysis, the new completion methodology appears to have restricted flow from the higher permeability intervals while permitting flow from lower permeability intervals. The methods used to plan and execute these production logging programs, and the integration of the interpretations into the pressure-transient analysis for the complex completions of multi-layered reservoirs, are discussed. Examples illustrating data quality and interpretation are provided.
Infill Drilling—Rig Time Optimization in the Gulf of Thailand
Authors: Yingvorapant Worawit , Christieson Richard
Published: December 2007

To meet increasing gas demands while drawing from the shrinking reserves of a mature field, CTEP (Chevron Thailand E&P) is drilling as many wells as economically feasible. Wells have to be drilled and completed very quickly to minimize rig time and reduce the "per well" drilling cost. In 2005, the average time to drill and complete a slimhole well was 6 days; the target for 2006 is 4.5 days.

During 2005, CTEP drilled and completed over 300 wells while 450 wells are planned for 2006. In addition to exceptional drilling performance in the Gulf of Thailand, value creation is enhanced by performing a high number of IFDP (in-fill drilling projects) whenever possible. This reduces cost by minimizing new platform construction, reusing slots, and reducing installation of new surface casing. The IFDP project can be categorized into two phases: (1) slot recovery; and (2) drilling. This paper focuses on phase 1 of the project, where CTEP uses HWO (hydraulic workover) systems along with cementing, slickline, and wireline services to perform the slot-recovery operations before rig arrival. Topics of discussion include current operational equipment, methods and procedures, logistical challenges, lessons learned, and new development plans intended to further enhance the operation.

Statistically, it is estimated that for each single platform 6-well abandonment campaign, CTEP gain 7 to 8 days of drilling time by not utilizing rig time for the Phase I operation. The drilling rig focus is, therefore, maintained on, doing what it does best, drilling new wells safely and economically. Additional wells are drilled with the time saved supplying early gas to meet Thailand's expanding industrial demands.
Case History of One-Trip Monobore Completion System—2 Years of Cement-Through Monobore Completions in the Gulf of Thailand
Authors: Chapman Walt
Published: December 2007

This paper will discuss a Monobore one trip cement through completion system. The system was designed to add artificial lift capabilities and improve safety to short life monobore wells. The disposable well bore concept is gaining popularity in regions worldwide. This paper will also discuss case histories including operation issues and problems and how they were solved.

Operational procedures will be outlined to effectively demonstrate, and discuss the decision making process when determining the most cost effective candidates for this technology.