bluuebunny/crossref_metadata_2025_split 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.