bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ahead of Bit Pore Pressure Prediction using VSP - A Case Study in South China Sea
Authors: Yuhong Xie , Jun Cai , Lingxia Zhen , Hong Tian , Yanhua Li , Voskamp Arne , Bailin Wu 
Published: July 2010

Abstract
Presented in this paper is a case study in South China Sea on formation pore pressure prediction ahead of bit by using a look-ahead vertical seismic profile (VSP). At the intermediate total depth (TD) of 2930m of the study well, wireline logs and VSP data were acquired, and VSP inversion conducted. A pore pressure model was calibrated based on VSP data and validated with the drilling and wireline data above the intermediate TD. The model was then applied to the VSP-inverted velocities below the intermediate TD to predict the pore pressure profile ahead of the bit. Following the successful drilling of the study well to the final TD, a second VSP, wireline logs and formation pore pressure measurements were acquired. The post-drill pore pressure evaluation revealed that the look-ahead pore pressure under-predicted the actual formation pore pressure by a small margin. A number of factors that would improve the accuracy of look-ahead velocity inversion, such as the presence of very low frequency range of the spectrum and application of constrain point(s), have been examined in the paper. Furthermore, it has been demonstrated that undercompaction is not the only overpressure mechanism in this study area, unloading may also have contributed to the overpressure. Both Bowers and Eaton models can be applied to predict pore pressure ahead of bit for the overpressure mechanisms in the area.
Well Test Analysis of Multiple Matrix-to-Fracture Fluid Transfer Fluid Transfer in Fractured-Vuggy Reservoir
Authors: Djatmiko W. , Hansamuit V. 
Published: July 2010

Abstract
This paper describes techniques to identify vugs in a real pressure buildup data. The reservoir under study is an under-saturated carbonate reservoir dominated by vugs and karst. We analyse the 80 hours of pressure buildup following a 100 hour of pressure drawdown. We observe the pressure derivative behavior cannot be described using current NFR models such as dual porosity and triple porosity models. This is because some pressure derivatives are obscured by reservoir boundaries and the matrix-to-fracture fluid transfer does not behave as it were in a multiple porosity reservoir. In this heterogeneous reservoir, we believe this corresponds to the number of matrix inter-porosity flow parameter, and thus degree of reservoir heterogeneity. If we force the data using dual porosity or triple porosity models, the error will be high (&gt;15%), because the pressure derivative cannot follow all the transition periods.
We use combined analytical and numerical methods to tackle this problem. First the dual porosity analytical solution is invoked to estimate the reservoir parameter (ω, λ and k). Next, a numerical triple porosity model is set up to represent the reservoir. The reservoir parameters initially follow analytical results as initial guesses. History matching procedures are performed to compare DST data with the calculated bottom-hole pressure. When these agree, reservoir flow capacity and storage capacity can be determined for fracture, matrix and vug respectively. We found volumes of vug cannot be ignored in a triple porosity system.
This technique can be used to quantify vugs or karst from well testing when analytical dual porosity or triple porosity model are unable to handle all matrix-to-fracture inter-porosity flow due to reservoir heterogeneity. Using this technique, we believe not all well test data in carbonate reservoirs (especially for high k.h) can be analyzed using current analytical models. Ignoring this, the estimated permeability is significantly different from the actual.
Evaluation of Sand Control Completion Alternatives and Asphaltene Deposition Treatments in the Area 2 Sur Field Maracaibo Lake Venezuela
Authors: Vladimir Vasquez C. 
Published: July 2010

Abstract
The main reservoir in the Area 2 Sur field is the Eocene C/VLG-3676, it is a consolidated reservoir located in the Maracaibo Lake (Venezuela), with recoverable reserves of approximately 572 MMSTB; this reservoir is characterized by complex challenges such as high temperature, sand production and asphaltene deposition. This paper provides a methodology to choose the most feasible completion alternative to minimize sand production and asphaltene deposition in this field. Several analyses were made to determine possible causes and solutions of sanding and asphaltene deposition. Also, a number of sand control techniques and asphaltene deposition treatments were technically evaluated to know the feasibility of each option in the field. Sand production wells are located mainly in the North and Central zone of the reservoir while asphaltene deposition it is common in the South region. Five techniques have been applied to minimize sand production, only production rate control has been successful in some regions of the field. Two asphaltene deposition treatments has been used in the field, only clean out have been effective in 60% of the wells applied. Sand production is originated from stresses generated by high production rate which exceed the rock resistance. Asphaltene deposition is because the crude oil composition is unstable, light paraffin and CO2 are present in the gas lift and the reduction of pressure below asphaltene onset flocculation. The optimum gravel size for the field is 8–12 US Mesh and the screen size is 1.25 mm, formation grain size of the reservoir Eocene C/VLG-3676 classify like medium uniform. Slotted liner and production rate control are technically feasible options to minimize sand production in the field. Magnetic treatment and production rate control are suitable to reduce asphaltene precipitation; economic indicators show that the well completion diagrams proposed is economically attractive in all regions of the reservoir.
Propagation of Regular HCl Acids in Carbonate Rocks: The Impact of an In-Situ Gelled Acid Stage
Authors: Gomaa A. M. , Nasr-El-Din H. A. 
Published: July 2010

Abstract
In-situ gelled acids based on polymer have been used in the field for several years, and were used in the field in stages between the regular acids. Literature survey reveals that certain plugging effects within highly permeable layers may occur and result in the diversion of the injected acid into less permeable zones. Recent studies indicated that sometimes diversion was not achieved with a severe damage that can lead to loss the whole well. There is no agreement on when this system can be successfully applied in the field.
Single-stage and multi stage-stages acid test of well performance were conducted using Indiana limestone cores (1.5 in. diameter & 20 in. long) at 250°F. 15 wt% regular HCl and 5 wt% in-situ gelled acid based on Fe(III) as a crosslinker were the acid that used in this study. Propagation of the acid, polymer, and cross-linker inside the long cores was examined for the first time in detail. Stage volume and injection rate, that were the parameters that affect on the propagating of various chemical species, were examined in details. Samples of the core effluent were collected and the concentrations of calcium, cross-linker, and acid were measured. Material balance was conducted to determine the amounts of polymer, and cross-liker that retained in the core.
Experimental results show that In-situ gelled acid should be pumped at low shear rates. In-situ gelled acid at low shear rate conditions instantaneously plugged the tip of the wormhole and didn't create additional wormhole inside the core. Therefore, when the final regular acid stage bypassed the gel, it started to propagate from nearly the last point that the first stage ended. This is to endure proper acid diversion. In-site gelled acid stage volume should not exceed 0.5 PV. No benefits were gained by increasing the volume of in-situ gelled acids. Retention of total iron in the core increased in multi stage acid treatments, especially at low injection rates.
Gas Blowdown Case Study: Striking a Fine Balance in Maximizing Gas Production Plateau and Minimizing Oil Loss: A Case Study of a Gas Blowdown Development Plan for a Mature Clastic Field in Oman
Authors: Garimella Sai , Kalbani Ali , Waili Ibrahim , Kasap Ekrem , Lamki Ali 
Published: July 2010

Abstract
PDO is a major operator in the Middle East with long production history for many of its oil fields. Due to the increased gas supply requirements, it is considering options for blowing down the gas caps of some selected oil fields to cater for the gas demand for achieving sustainable oil production.
The key challenge for these gas blow down is to maximize gas production plateau while simultaneously minimise associated oil recovery losses.
This Case Study illustrates the Gas Blowdown optimisation of a saturated clastic oil reservoir. During the Blowdown Study, optimum gas production rates from each of the Upper and Middle Gharif reservoirs are targeted to meet a given gas production plateau rate. A fit-for-purpose assessment for the impact of subsurface parameter uncertainties on the proposed development demonstrated robustness of the gas production plateau period. This analysis resulted in a Gas production Plateau period ranging from 4 years (Low case) to 7 years (High case) with an expectation case of 6 years.
Multiple Subsurface & Surface development scenarios have been evaluated including lowering pressure ratings for the Separator inlet pressure. The oil & gas production profiles thus generated have been evaluated for robust economics and used for final concept selection & field implementation. Furthermore to minimise oil losses various optimisation efforts have been identified during pre and post blow down phases in terms of re-perforations, gas lift implementation and blow down oriented well and reservoir management practices.
This case study proposes an optimised Gas Blowdown field development by maximizing gas plateau period while minimizing associated oil loss. The Study resulted in selecting the appropriate surface development concept, operating specifications and provided an optimised field management plan during the Blowdown phase. The methodology adopted in this case study should find wider applicability in the industry.
Study of Tracer Test Application for Gas Reservoir Characterization During Underground Gas Storage Process
Authors: Moradi B. , Tahami S. A. , Shariatpanahi S. F. 
Published: July 2010

Abstract
In today's world demand for natural gas as a source of energy has been increased. Especially in Iran the main source of home's heat energy is natural gas. In fall and winter demand for natural gas increases that may exceed the amount of total gas production. Underground gas storage is an activity, which allows to efficiently resolve demand seasonality problems. Natural gas injection and storage in depleted gas reservoirs is a common challenge that overcomes this problem. The aim of this study is to use tracer test method as a way to better understand a gas condensate reservoir to use it as a UGS. Case studies showed that gas tracer technology is one of the best methods for improving reservoir characterization and description of gas storage reservoirs. So it is well known in the petroleum industry that tracer data can provide valuable information on reservoir characteristics and fluid flow performance. The reservoir under study in this work is a limestone gas condensate reservoir with high porosity and good permeability, which is located in south of Iran. Therefore, in order to better characterize the reservoir it was decided to implement tracer test in this reservoir. However, a prerequisite for obtaining reliable information is careful planning, design, and experimental investigation. So different reservoir studies such as geological studies, well logging, and well testing was implemented to describe the reservoir truly. By means of these studies, reservoir operation can be predicted and controlled. In order to find the best tracer and its volume, a comprehensive study on the effects of tracer volume, concentration and adsorption on some plugs was also performs. Finally, it was concluded that Helium is the best tracer for this reservoir, because of its low interaction with rock and fluid and also same velocity with the bulk of fluid flow.
Comparison of Computational Fluid Dynamics of Erosion in Coiled Tubing on Various Wrap Diameters
Authors: Bailey M. , Blanco I. L. , Rosine R. S. 
Published: July 2010

Abstract
Coiled tubing (CT) is widely used in well intervention as a practical and cost-effective means of servicing wells. Since CT's inception, the actual flow through CT has been a point of discussion and theory. Testing has been conducted to study what occurs inside the CT. In recent years, the use of computational fluid dynamics (CFD) software has provided greater insight into actual CT flow patterns, including fluid-flow velocity profiles and secondary flow regimes. CFD helps to understand the fluid-flow phenomenon, which leads to effective application of friction-loss gradients. CFD has proven to be an effective alternative to full-scale testing.
This work compares the results of CFD modeling of internal erosion caused by proppant to actual field data. This paper investigates the increased erosion rates found in the area of tubing that is on the tubing reel during pumping operations. Specifically this paper will investigate how the wrap diameter influences erosion rates as indicated in field data. It compares predicted values, actual values, and computed values from CFD analyses. Results from this work and previous work can be used to correlate a predictive model of erosion rates that can be applied to correct wall-thickness values used in bending fatigue models and force limit calculations. CFD was used to provide correlations for the predictive model without full-scale testing, which greatly reduced the cost of development. Fluids investigated include slurry pumped from an actual job.
Milling Out Plugs in Bakken Horizontal Wells with the Aid of a Coiled Tubing Tractor
Authors: Krueger E. , O’Neal E. , Moore N. B. 
Published: July 2010

Abstract
The Bakken offers the largest potential for technically recoverable reserves in the US; that potential has increased because of new practices utilizing multi stage frac operations. Many Bakken wells have long cased horizontal sections up to 10,000 feet with composite plugs/frac ports set at 500-1000 ft intervals allowing greater fracture uniformity along the producing horizontal section. After frac, current practices dictate that the well must be cleaned and the plugs milled to facilitate maximum future production. This operation has frequently been accomplished using coiled tubing alone. However, the length of the horizontal section of these newer wells frequently results in some plugs being left behind in the well due to CT's inability to perform operations at or near TD. An improvement to current practices would be to utilize a coiled tubing tractor to clean out and mill the remaining plugs past the reach boundaries of CT alone. This new practice was implemented successfully on two wells in the Bakken resulting in fewer plugs (zero plugs in one case) left in the well and increased future production. The case histories of these two wells along with lessons learned are described.
Deliquification of South Texas Gas Wells Using Corrosion Resistant Coiled Tubing: A Six Year Case History
Authors: Poppenhagen K. L. , Harms L. K. , Wilkinson R. , Glover D. E. 
Published: July 2010

Abstract
Running coiled tubing can be an effective tool to deliquify gas wells, but this practice was discontinued in early 2000 in ConocoPhillips Lobo Field in South Texas because of problems experienced due to CO2 corrosion with standard coiled tubing metallurgy. Since 2004, ConocoPhillips has installed 90 corrosion resistant coiled tubing velocity strings as an alternative to conventional carbon steel coiled tubing. These installations have yielded 5 mmcfd in incremental gas rate and the change to a corrosion resistant metallurgy has drastically reduced the high failure rate and costly workovers that resulted from previous carbon steel installations. Various key learnings including candidate selection criteria and future application recommendations will be presented in addition to representative well types and production profiles. Metallurgy comparisons, post-use inspection findings and full-cycle cost implications will also be presented.
Numerical Analysis on Subsalt Wellbore Stability in the Vioska-Knoll Deepwaters of the Northern Region of the Gulf of Mexico
Authors: Shen Xinpu , Bai Mao , Smith Russell 
Published: July 2010

Abstract
The goal of this paper is to present a best practice for deep water sub-salt wellbore stability analysis. Conventional one-dimensional analytical tools and three-dimensional nonlinear finite element method (FEM) software were used jointly in an integrated manner in which the former was used to predict pore pressure with logging data, and thus provides input data for FEM analysis. Numerical results of sub-salt wellbore stability analysis were presented for the Viosca Knoll field in the deepwaters of the Gulf of Mexico. To obtain accurate stress field information around the salt, it is necessary to begin by performing an analysis at the field scale. This analysis presents correct boundary conditions for wellbore stability analysis at the wellbore-section scale. Submodeling techniques were used to manage the field-to-reservoir scale discrepancy. A field model, 10 km in depth and width, was built, and a pan-cake-shaped salt body with a diameter of 7 km was embedded in the model. Trajectory optimization was performed once the vector distribution of principal stresses was provided. At the wellbore section scale, a submodel was built and the minimum safe mud-weight gradient was numerically predicted. A variation in the axial direction of the wellbore was performed to determine the optimized wellbore direction at the salt exit. The proposed integrated approach of jointly using conventional analytical tools with FEM software offers an effective method and best practice for deepwater sub-salt wellbore stability analysis.
Integrated Geology, Geophysics and Petrophysics Data to Describe Lateral and Vertical Reservoir Heterogeneity to Optimize Field Development Plan Limau Field, South Sumatra Basin, Indonesia
Authors: Nugroho Susanto Budi , Hartono Yedi , Ardianto Reza Nur 
Published: July 2010

Abstract
Limau Field is located in South Sumatra Basin, form as anticlinorium elongated from West – East. Limau Field are divided into 8 blocks and separated by normal fault and have been produce since April 1951. Description reservoir is needful in detail either lateral or vertical that can describe reservoir heterogenity in process designing and proposing a field development plan. Build a 3D model in Limau Field are challenge, which caused by complexity in stratigraphy and restrictiveness data. Integrated of multidiscipline science are needful to construct a static 3D model that can describe heterogeneity reservoir in Limau Field.
Interpretation detail in geophysics and geology were doing by integration between petrophysics and core data. Seismic enchantments are conducted to increasing a quality of 2D seismic data in Limau Field and used to build an attribute seismic Pseudo-GR and Acoustic Impedance. Attribute seismic pseudo-Gamma Ray and Acoustic Impedance map were used to describe generally in lateral distribution reservoir. Log data and Biostratigraphy were integrated to decide depositional environment furthermore the correlation geology was built by sequence stratigraphy concepts. Identification of lithofacies was built by integration between log data and petrography, and those data are applied to wells that have no in core data; it will be used to estimate a distribution of reservoir properties in throughout field. Analysis of log is use to found a reservoir properties which validated by core data. Synthetic of logs (Neutron & Density) are approach by neural network concepts then obtainable the sufficient data for analysis of log in wells that have incomplete log data. Relation between porosity, permeability, and vclay are using as phenomenon to define flow unit with the result that estimation of permeability can be done throughout field.
Fine geology model are build for 50 zones with total grid cell 97.886.742 with large scale of geology model; influences of variability regional toward reservoir quality can be seen. Application of geostatistic are use to build a model of lateral distribution and lithofacies vertical which guiding by attribute seismic map and facies pie from well as a trend and probability of distribution. Reservoirs properties are distributed by constrain sand zone and llithofacies. 25 of realization models are building by geostatistic application for each zone furthermore by blind test model is use as a validation of lithofacies distribution model and reservoir properties. Based on suitability of well production data then 5 final models have been chosen.
A Comparison of the Cultural Impacts on Leadership Preferences Between Overseas Chinese Petroleum Professionals and GLOBE Scores
Authors: Li Y. , America B. P. , Duncan P. , Green M. 
Published: July 2010

Abstract
From 1978 to 2008, almost 1.4 million of Chinese students have benefited from China's "open door (to the West) policy" and have studied in the U.S. and other Western universities. This group of scholars truly crossed the globe and brought with them diversity of culture from the East to the West. Among the Chinese professional group, the Chinese petroleum professionals have led the way for this movement. The purpose of this study was to meet the cross-cultural research and business needs in global business and leadership development. In particular, the study focused on a group of Chinese petroleum professionals who grew up in mainland China, were educated first in China (undergraduate level), immigrated to U.S., achieved higher education in the U.S. (graduate level), and have been integrated to U.S. society. This group of scholar-practitioners plays important roles in their organizations not only through technical expertise, but by also understanding first-hand the cultural impacts of globalization in the oil industry and the other organizations. This study focused on cultural and leadership behavior preferences of the study group and compares the global leadership preferences of this group against the reported Chinese culture and leadership scores in the GLOBE study. This research found significant differences between the two groups, and it further demonstrated differences between the study group's scores and the GLOBE study scores for the U.S., Taiwan, and Hong Kong. The comparisons attempted to establish the cultural impact of context on the leadership preferences from this focus group.