bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Navigation Quality of Non-Survey Logging or MWD Tools and Methods of Navigation Sensor Correction and Reconstruction
Authors: Tracadas Philip , Bonavides Clovis , Quirein John , Perkins Tegwyn 
Published: September 2011

Abstract
The techniques used to process open- and cased-hole image logging and other oriented tools that are run in offshore exploration and development wells require highly accurate navigation logs. Navigation packages usually consist of triaxial accelerometers and magnetometers that require calibration of the offset (bias), gain, and tool axis alignment for each sensor. Despite pre- or post-acquisition surface calibrations, the downhole environment will alter calibrations of offset and gain as a result of many factors, such as temperature and electrical noise. These factors are impractical to characterize or predict, and it is impossible to completely isolate the navigation package from these factors. Experience shows that the offsets and gains of the sensors may change appreciably over time scales much shorter than the total logging time.
This paper provides four detailed examples of possible navigation logs with various problems to develop a methodology for evaluating their quality and proposing corrective action. The goals of this study are to determine which navigation sensors to adjust or which sensors are not responding to the appropriate Earth field and need reconstruction. The paper proposes several quality measures for identifying, from the navigation log, drift in sensor response, including measured total field variations and correlations of tool deviation to tool rotation.
When the methods described in this paper are used to align images with respect to a geographical reference (in cases where the navigation was affected by sensor failure or external factors, e.g., permanently magnetized formation layers, that alter the sensor calibrations), they significantly enhance the navigation quality. For example, image logs that originally wobbled erratically in ferrous formations can be oriented to the north allowing dipping-bed orientation to be measured. In addition, magnetometer reconstruction and accelerometer correction can easily manage oriented navigation in metal casing. In general, the algorithms developed in this study assume that a rough surface calibration is available to obtain an initial solution, but time is no longer required for meticulous wellsite surface calibration.
Case Study: The Research Progress of Using Stimulation Technologies in Horizontal Wells to Develop Low-permeability Reservoirs
Authors: Jianwen Yan , Yurong Zhang , Wenjun Wang , Cheng Cai , Na Zhang , Bairu Shi 
Published: September 2011

Abstract
In the last three years, the horizontal well technology was developed at high speed in PetroChina, and the number of applications was more than 3000 by the end of 2008. This paper focuses on the stimulation technologies in horizontal wells and the latest research progress of using them to develop low-permeability reservoirs in PetroChina. To solve the problem in the development of low-permeability reservoirs, PetroChina carried out the researches including the adaptability study of drilling horizontal wells in low-permeability reservoirs, the matching relationship study of horizontal wells with different well patterns, the stimulation technologies, such as fundamental acid fracturing technology, staged hydraulic fracturing technology in a perforation completed horizontal well, liquid slug staged fracturing technology, mechanically staged fracturing technology and limited-entry fracturing technology, etc. Several breakthroughs had been made in the key technology research, and the new technology had been applied to 405 wells in field tests, which acquired good effect during 2007 to 2009. After stimulation, the maximum individual well production came up to 4.2 times of the adjacent wells, and a great deal of experience had been accumulated during these tests at the same time which would provide technical support for the application of horizontal wells in the development of low-permeability reservoirs.
EOR Potential in the Middle East: Current and Future Trends
Authors: Al-Mutairi Saad M. , Kokal Sunil L. 
Published: September 2011

Abstract
The majority of enhanced oil recovery (EOR) projects are being executed in the the U.S., Canada, Venezuela, Indonesia and China. The volume of oil produced by EOR methods increased considerably from 1.2 MMBD in 1990 to 2.5 MMBD in 2006 (Sandrea and Sandrea 2007). Current total world oil production from EOR is approaching 3 MMBD representing about 3.5% of the daily global oil production (Sandrea and Sandrea 2007). Thermal and CO2 methods are the major contributors to EOR production, followed by hydrocarbon gas injection and chemical EOR. Other more esoteric methods, e.g., microbial, have only been field tested, without any significant quantities being produced on a commercial scale. In recent years, the number of EOR projects has increased with escalating oil prices.
The number of EOR projects in the Middle East (ME) has also increased over the past decade. In some countries like Oman, there has been no choice but to implement EOR projects aggressively due to dwindling "easy oil." Other countries in the region have also started to think EOR, and are including them in their strategic short-, medium- and long-term development plans. Furthermore, there are many projects on the drawing board and appropriate screening studies and EOR pilots are being pursued region-wide. This paper reviews the current ME EOR projects from full-field development to field trials, including those on the drawing board. The option of advanced secondary recovery (ASR) — also known as improved oil recovery (IOR) — technologies before full-field deployment of EOR is also discussed. A case is made that they are a better first option before deployment of capital-intensive EOR projects. The ME’s general drive towards "ultimate" oil recovery — instead of immediate oil recovery — is highlighted in the context of EOR. Some of the enablers for EOR in the ME are also discussed in the paper. It highlights the opportunities and challenges of EOR specific to the region.
Success Story: Improving Reservoir Monitoring to Reduce Workover Cost & Increase Production in Offshore Marginal Oil Field
Authors: Pramboeidi Sri Khresno , Subiantoro Edy 
Published: September 2011

Abstract
Mengkapan is an offshore field in KPSA area. It is located between Sumatra, Padang Islands, Malacca Strait. Cumulative production from Mengkapan is 35 MMSTB since 1986 from 11 wells. The field, with recovery factor 50%, is considered as mature field. The wells produce commingles from several zones cross flow and production blocking occur due to difference pressure regime of each zone.
When the well is suffered from production declining, production spinner logging is run to monitor flow contribution and water cut from each zone. The result will be followed up with zonal isolation program by setting production packer at watered zone. Along the time, there will be no more zones to be isolated with packer but to abandon the well when the production declines again. Therefore, squeeze cementing is proposed.
C/O logging is performed prior to squeeze cementing. Cross flow is believed only occurs in high permeability interval and will not effect the reading. Remaining oil saturation up to 40% is found at the top of perforation and low permeability interval even the zone is predicted as watered zone from production spinner logging. Cement is squeezed and oil-bypassed interval is re-perforated. Squeeze cementing technique is also improved based on cross flow information from production spinner log.
EB well produced 9000 BFPD, 99.5% WC, 45 BOPD prior to squeeze cementing, now it produces 2000 BFPD, 94% WC, 120 BOPD. The budget for cementing was proposed up to USD 660,644.00 based on experience from other well and only 60% from the budget was used.
This paper explains improving reservoir monitoring helps to increase workover success ratio (reduce operation cost, and maximize gain) from concept, data gathering, until field application. The challenge is to change mindset from "no remaining oil" to "there is oil by-passed".
Study and Application of Anionic and Cationic Polymers Alternative Injection for In-depth Profile Control in Low Permeability Sandstone Reservoir
Authors: Caili Dai , Qing You , Xiqun Fan , Yuandong Peng , Guang Zhao , Ping Wang , Xiuying Wang , Fulin Zhao 
Published: September 2011

Abstract
In view of characteristics of low permeability sandstone reservoir and the aim of water control and oil increment, a mild water control technology referring to the alternative injection of anionic and cationic polymer for in-depth profile control in low permeability sandstone reservoir was proposed and developed when the oil wells were in high water cut stage. The adsorption equilibrium mass concentration of the cationic polymer is 1500 mg/l and the adsorption equilibrium time is about 8 hours, while the adsorption equilibrium mass concentration of the anionic polymer is 1000 mg/l and the adsorption equilibrium time is about 6 hours. The physical simulation experiment shows that anionic and cationic polymers alternative injection and prior injection of cationic polymer with high plugging capacity are better than the single polymer injection. The plugging capacity increases with the increase of injection rounds, the optimized injection round is no more than 3 times according to economic benefit. This technology is successfully applied in Shuangqian 6 well of Henan oilfield in June 2010. After treatment, the high permeability channel is effectively controlled, the water cut obviously decreased and the oil production increased, it is shown that this technology is a reliable and feasible technology and worthy to be widely applied in low permeability sandstone reservoir.
Evaluation of New Well Configurations for SAGD in Athabasca McMurray Formation
Authors: Tavallali M. , Maini B. , Harding T. 
Published: September 2011

Abstract
The Athabasca oil sands deposit is the largest oil sands deposit in Alberta-Canada which contains about 1.7 trillion barrels (270×109 m3) of bitumen in-place. In the Athabasca oil sand, most of the bitumen deposits are found within a single contiguous reservoir, the lower cretaceous McMurray Formation.
Since mid 1980’s, SAGD process feasibility has been field tested in many successful pilots and subsequently through several commercial projects in Athabasca-McMurray Formation. However, SAGD remains very energy intensive, extremely sensitive to geological and operational conditions, and an expensive oil recovery mechanism. Over the 20 years of SAGD experience in Athabasca, the only well configuration that has been field tested is the standard 1:1 configuration which has a horizontal injector lying approximately 5 meters above a horizontal producer.
This study examines the impact of using several modified well configurations for SAGD in the McMurray Formation in Athabasca in order to improve process performance. The technical feasibility of applying each arrangement was evaluated through sensitivity analysis. Numerical modeling was carried out using a commercial fully implicit thermal reservoir simulator; Computer Modeling Group (CMG) STARS 2009.13. The wellbore modeling was utilized to account for frictional pressure drop and heat losses along the wellbore. The reservoir properties were selected in order to accurately represent of the McMurray Formation in Athabasca.
The new well configurations provide operational and economical enhancement to the SAGD process over the standard well configuration in Athabasca area. The SAGD process response to different reservoir parameters of the McMurray Formation, such as mobile water saturation and reservoir heterogeneity in the form of bioturbated shale, has been investigated for the most promising of the new well configurations.
The Use of Downhole Temperature Data in Gas-Oil Ratio Estimation and Reservoir Management
Authors: Deucher R. H. , Gomes R. M. , Aniceto P. H. , de Souza C. N. , de Assis J. P. 
Published: September 2011

Abstract
In Campos Basin, deepwater offshore Brazil, permanent downhole gauges are used to record pressure and temperature. Pressure data are used extensively in well analysis, but temperature data have seen little use. Production data indicate that downhole temperature changes as a function of flowrate, pressure and fraction of fluids. A strong relationship was observed between flowing temperature and gas-oil ratio (GOR), caused by cooling upon expansion. It has also been observed that temperature data can be used to detect scale occurrence, aiding reservoir management. This paper proposes a methodology based on a semi-empirical equation that makes use of downhole temperature data to estimate GOR. The energy balance applied to the wellbore was simplified to generate an equation suitable to use with easily obtainable field data. The resulting equation has two unknown parameters, which are obtained by adjusting the model to field data. The inputs used to calibrate the model are GOR, oil flowrate, watercut and downhole temperature. The use of this methodology to three horizontal wells will be presented. For well C, the mean error obtained while estimating the GOR measured at the tests was 6.6%. In well B, the mean error was 11%. Well A has passed through a wide range of liquid flowrates, and over the 150 production tests that were performed before water breakthrough, the model was able to estimate the GOR with a mean error of 5.4%. However, after water breakthrough it could not reproduce the measured data accurately. In Campos Basin, accurate GOR measures are difficult to obtain, particularly after gas-lift start-up, because gas flowrate measurement is unreliable and test separators are often unavailable. Using this methodology, it is possible to obtain estimates of the GOR, which is desirable for an improved definition of the waterflood strategy and as a refined input for material balance in specific regions of the reservoir.
Experimental and Simulation Analysis of CO2 Storage in Tight and Fractured Sandstone under Different Stress Conditions
Authors: Farokhpoor R. , Baghbanbashi T. , Torsæter O. , Lindeberg E. , Mørk A. 
Published: September 2011

Abstract
Sequestration of carbon dioxide in a saline aquifer into shallow marine formation of Jurassic sandstones in Svalbard has been studied on unfractured cores and by using a simplified set of geological boundary conditions. In this paper, the feasibility of storing CO2 in a fracture and matrix system in a low permeable formation is studied by performing a series of laboratory experiments under different stress conditions. Laboratory core flooding experiments were conducted on two alternative fractured and unfractured cores. Water and nitrogen were injected into brine saturated cores at the reservoir conditions. The result shows that core plugs are very tight and the liquid permeability even for fractured core is less than 1 millidarcy. Under increased acting stress from 10 to 180 bar, the effective permeability of fractured core is reduced by 73 percent and fluid flow occurs through both fracture and matrix.
A conceptual, generic and simple 3D numerical model using commercial reservoir simulation software and available petrophysical data was used to study the CO2 injection through fracture at different overburden pressure. The effect of different overburden pressures were applied by using respective permeabilities in simulation model. Mean pressure along the cores was used to match simulation predictions with experiments results. The result shows that even though the system is water-wet, and matrix has a very high capillary pressure, CO2 flows through both fracture and matrix. The amount of CO2 that flows through the fracture is high and is reduced by increasing overburden pressure. The quantity of dissolved CO2 in brine phase reduces by decreasing overburden pressure and increasing permeability. The faster the CO2 is flowing through the fracture less time is available for CO2 to trap as residual phase and dissolve in brine. In dipping fractured saline aquifer, CO2 plume movement in updip direction is accelerated by decreased overburden pressure and increased permeability.
Integrated Drilling and Completion Data Workflow into a Strategic Data Management Solution: An Implementation Case Study from Cairn Energy India
Authors: Peytchev Peter , Thummar Dinesh , Singhal Rohit , Rosland Habil Akram , Tracy Simon 
Published: September 2011

Abstract
In 2008, Cairn Energy India, Ltd. (CEIL) recognized the importance of tackling unstructured data across the drilling and petroleum engineering group, where significant use of a proper workflow and a state-of-the-art data management application system have been promoted within the organization. The project rollout was aimed to achieve absolute integration of drilling and completion information into one centralized database system.
Over the last 10 years, the drilling and well services group has used the knowledge management system to achieve targeted maturity involving the conversion of a large volume of data into a reliable, yet simple, synchronized and structured data form. Collaboration between departments and vendor's application was needed for the CEIL process to remain effective following the company's aggressive growth.
This system was initially designed to generate schematics, reports, and queries. A specific workflow and process culture was required to ensure that all critical data, including operation-related information, are being captured meticulously during the lifecycle of a well.
Factual integration between the drilling and completion system was only possible after combining the thousands of reports into a centralized data management system. CEIL initiated the data management project to achieve reliable and accessible information across this domain, thus improving the group's productivity and operational efficiency.
This integration further facilitated the common access point for engineering personnel. In addition, it minimized the data entry workflow and effective use of decisive historical data. Data, once recorded, can be used by multiple applications intended for engineering, well-planning analysis, and operational monitoring. This integration has improved data quality and facilitated timely and cost-effective decision making.
This paper explains the methodology, strategy, and technology implemented in the data management project.
A Novel Technique for Monitoring Hydrate Safety Margin
Authors: Yang Jinhai , Chapoy Antonin , Mazloum Saeid , Tohidi Bahman 
Published: September 2011

Abstract
A novel technique has been developed for optimizing hydrate inhibitor dose rates by monitoring the actual hydrate safety margin. The technique is based on measuring acoustic velocity and electrical conductivity in an aqueous sample taken from the pipeline/separator. The developed system then determines salt and organic inhibitor concentration (e.g., methanol, mono ethylene glycol, kinetic hydrate inhibitors, etc). In the case of thermodynamic inhibitors the information is then fed to a thermodynamic model determining the hydrate stability zone. Superimposing the pipeline operating conditions (e.g., P&T profile) the developed system can determine the hydrate safety margin. The system can provide warning if the operating conditions is inside the hydrate stability zone or too much inhibitor is being injected.
The technique can be used in optimizing inhibitor injection rates, reducing the impact on the environment and operational costs. It can also improve the production system reliability by constant monitoring hydrate safety margin and protecting the system against pump malfunction and/or changes in process variables (e.g., water cut).
The above technique has been developed through a joint industry project and its performance has been intensively evaluated using the synthetic samples and real produced water samples by the authors, the project sponsors and field trials. The results demonstrate that this system can be used for different inhibitor systems including methanol-salt, mono ethylene glycol-salt, and kinetic hydrate inhibitor-salt systems with good accuracy.
The developed system can have a major impact on reducing the inhibitor injection rates, reducing environmental impact, and improving the reliability of production systems against risks associated with hydrate formation. The developed system can be lab based, mobile unit or on-line with near real time taking samples from live pipelines/separators.
Automatic Production and Seismic History Matching by Updating Locally and by Geological Environment in the Nelson Field
Authors: Kazemi Alireza , Stephen Karl D. 
Published: September 2011

Abstract
It is becoming common to use automatic or assisted techniques for history matching of oil and gas reservoirs. These techniques are complicated by the need to update the properties of the model that are linked to the geological representation of the reservoir but also affect the misfit between observations and prediction. In this work we compare updating of regional properties for the former while updating local properties to satisfy the latter.
We apply an automatic history matching approach to the Nelson field, a channelized turbidite reservoir, in order to better match the production rates of oil and water by well. We also integrate time lapse seismic data and we compare the result with production history matching output. We control the shale distribution within and between the major channel complexes by updating on the basis of geological environment variables which are regionally distributed. We compare this approach with more local updating by using pilot points with Kriginig.
By updating the reservoir properties by environment variables we reduce the total production history match misfit by 22% for six years of data. We also improve the forecast of a further three years by 20%. By updating locally after by environment, this improvement is 60% and 30% in the matching and forecasting periods respectively. By integrating time lapse seismic data in history matching to update by environment, the production misfit is reduced by an equivalent amount while forecasting is improved by 19%. Seismically we reduce the misfit by 7%.
Appropriate updating of the reservoir model is very important for reservoir management to reduce risk in development and to select appropriate models for forecasting. By updating the reservoir based on honouring the geological information or by using the geostatistical tools we can obtain a better representative of the reservoir with stronger prediction capability.