bluuebunny/crossref_metadata_2025_split huggingface dataset:
Thin Oil Columns Horizontal Wells Optimization Through Advance Well Placement Application in West China
Authors: Xin Song Yu , Xin Mai , Lin Du Hong , Qing Li , Hua Zhang Zhong , Halomoan Parlindungan M. , Bin Yang , Mi Zou , Yang Liu , Koon Lee Tow 
Published: July 2010

Abstract
Lu Liang is an oil field that has been producing for nearly 10 years. Thus, bottom water level has increased and accumulates remaining unproduced bypass thin oil columns reservoirs within the field. Horizontal well is recognized in rejuvenating these thin oil columns and since the oil column is thin at the top of reservoir with bottom water drive, the placement of the horizontal section near top of the reservoir is the key in avoiding early water break through, minimizing attic oil and optimizing reserve recovery.
The team recognized the existing conventionally-steered horizontal wells with standard technology cannot guarantee the optimum placement near reservoir top due to existence of great subsurface challenges. The short-comings to be overcome are:Exiting from the reservoir resulting in low reservoir contact, low drainage area and low recovery factor;Inability to maintain distance to reservoir top resulting in bypassed oil, early water break through and low recovery factor.
In this paper, technical assessment and filtration by the team enrooting to the successful selection and implementation of advance Well Placement Distance-to-Boundary technology to overcome the challenges will be highlighted. Subsequently total of 25 and 19 horizontal wells had been completed in 2008 and 2009 successfully and placed within 0.5 m below the verge of reservoir top without exit, keeping the well away from OWC. The success is registered with better Productivity Index based on well performance test done and the wells have been producing more than 90% oil whilst five times increase in production observed since put into production. This application had put the horizontal well in the optimal position possible for draining. Hence, oil incremental and longer production sustainability can be achieved and it has enabled horizontal wells to be economically developed in a thin oil-bearing zone in Lu Liang field and other similar fields in China.
Production Monitoring and Surveillance of ESP Wells—Maximizing Production and Recovery in a Volatile Economic Environment
Authors: Salim Muzahidin M. , Saenz Dan , Jadid Maharon , Rafea Mahmoud Abdel 
Published: July 2010

Abstract
The satisfaction of completing a workover project and handing wells back to operations is just the beginning. The ongoing surveillance and constant adjustments towards optimization will ultimately determine the success or failure of such an undertaking. This is particularly true with Electrical Submersible Pumps (ESPs).
In mid-2009, the first three production ESPs in Malaysia were commissioned and started offshore Sarawak in the Bokor Field. These were a step change in field operations as all other wells are produced primarily via gas lift. A great deal of planning and preparation was required to analyze well output against baseline calculations, test each well thoroughly to monitor for water breakthrough or sand, and monitor the platform infrastructure to ensure the additional loads and production expected.
Online surveillance has played a key part in assisting the project team towards optimizing the wells and observing pump performance. The system as installed has allowed for remote frequency changes to adapt the pump for current conditions. Additionally, the surveillance system has been employed to protect the pump during unplanned shutdowns.
The production results thus far show that the ESPs are producing several hundred barrels oil greater than the gas lift baseline. Solids have not been an issue and the production GOR has been amongst the lowest in the field. However, the objective from the project execution plan is to continue increasing to 1700 bopd incremental. To achieve this, the project team will need to continue the workflows and processes developed to ensure a successful ending.
A Method to Quickly Estimate the Probable Value of Shale Gas Well
Authors: Dougherty Elmer L. , Chang Jincai 
Published: July 2010

Abstract
We give test results for the simple exponential model and the power-law exponential model for predicting shale gas production. Three parameter estimation methods tested show that analytical procedures are far superior to derivative methods. Economic evaluation tests show that economic factors may be more important than the details of the forecasting model used.
Catalytic Properties of Clay Based Hybrid Materials for Drilling Operations
Authors: Lee Jung-Kun , Son You-Hwan , Tran Phuoc , Soong Yee , Martello Donald , Chyu Minking 
Published: July 2010

Abstract
Iron-clay nanohybrid particles which are comprised of clay matrix and embedded rod-like iron nanoparticles have been succesfully prepared via intercalative route, and their magnetic property and caltalytic efficacy have been verified using magnetometer measerment and Fenton reaction.
Environmental Regulations, Technology, and Cost of Compliance for Oil & Gas Operations
Authors: Rana S.. 
Published: July 2010

Abstract
The purpose of the paper is to emphasize the balance between cost of extraction & production (E&P) operations and complying environmental regulations to gain a better understanding of reducing overall costs associated with today’s oil and gas production while discussing importance of relevant technological innovations.
Due to recent coherent global initiatives on environmentally safe energy production and use, it has become increasingly important that the industry constantly search & implement a practical balance between environmental regulations and use of best available technologies with objectives of cost savings, not only to comply with the regulations but also to keep the operations sustainable for both small and large companies. The industry nearly spends as much on environmental protection as it spends searching for new domestic supplies of oil and gas; roughly 9 cents per gallon of gasoline (U.S. Department of Energy), amounting to over $10 billion a year. The cost of compliance with environmental regulations places a substantial economic burden on industry.
With this perspective, some specific conclusions and successful cost reduction technologies are listed along with general compliance items and costs data for each item (e.g., inspections and testing for drip & leaks, corrosion, costs incurred to safely dispose wastewater, etc).
The paper further highlights cost factors based on surveys/industry data, including situations when full implementation of latest E&P technology was lacking. As an example, in recent past, producers spent more than $3 billion per year in the US to comply with environmental regulations only. For some, combined estimated costs sustained an overwhelming net loss of about $4 to $5 per barrel (including roughly 20% cost of compliance) making very difficult to sustain E&P operations. Therefore, paper discusses the importance of balance between costs of overall operations and environmental compliance in most practical ways to benefit both small and large companies.
The Ejector Technology in Oued Zar Plant
Authors: Abdelli H.. 
Published: July 2010

Abstract
The Oued Zar process is continuously progressing and growing. In fact, the exploitation of the new well reserves engendered an important increase of the quantities of oil and gas to be treated. One of the major issues associated to this evolution was to optimise the process and to consider environmental impact. The purpose of this work consists on the application of the ejector technology in real case.
The ejector is a pump-like device that uses the Venturi effect of a converging-diverging nozzle. It converts the pressure energy of a driver fluid to velocity energy. A low pressure zone is created and entrains a suction fluid. After passing through the throat of the injector, the mixed fluid expands and the velocity is reduced, thus recompressing the mixed fluids by converting velocity energy back into pressure energy.
ENI Tunisia had previous experience using the ejector technology in Oued Zar plant. The Ejector design is specific. It’s intended to suit an individual case requirement for maximum operating efficiency. Thus, for the conceptual phase, first step of the project, real field data (the gas outgoing of separator and the driver gas characteristics) are required. This information is obtained by CPG analyses and pressure measurement. Then, the performance of ejector is evaluated for different drive flow. The second step consists on field installation. The ejector started up in December 2006. The excellent results obtained during the test were confirmed. The ejector is still working with high performance and very low maintenance cost.
This experience confirms the first field installation of ejector was successfully accomplished in the Oued Zar oilfield in 2006 and encourages using it for other similar projects.
Profile Modification in Injection Wells Through Relative Permeability Modifiers: Laboratory Validation and Reservoir Simulation
Authors: Vasquez Julio , Miranda Carlos 
Published: July 2010

Abstract
Waterflooding is a well-established technique in the oil industry to improve hydrocarbon recovery in a given reservoir. However, in the absence of profile modification, water injected into the reservoir will go into the high-permeability zones and will bypass the oil-saturated, low-permeability zones. This paper presents the laboratory validation and reservoir simulation of a relative permeability modifier (RPM) used for profile-modification improvement in injection wells. By injecting the RPM within the high-permeability zones, subsequent injected water will be diverted into low-permeability zones to improve the sweep efficiency of the waterflooding project.
This RPM is a water-soluble relative permeability modifier initially developed for water control in production wells. The polymer functions by adsorption onto rock surfaces and effectively reduces water flow with little or no damage to hydrocarbon flow. These treatments are extremely easy to mix and pump, and require no post-job shut-in time. This RPM was evaluated in 5- and 10-ft sandpacks to investigate parameters, such as depth of penetration, diversion properties, treatment injection rate, and polymer concentration. Laboratory results indicate this RPM can effectively penetrate through a 10-ft sandpack, providing permeability reduction to water throughout the length of the porous media. In addition, excellent diverting properties were observed while bullheading the treatment in sandpacks in parallel with significant permeability contrast.
In addition, a 3-D numerical simulator was used to evaluate the performance of the RPM system under different scenarios and varying parameters, such as (1) permeability contrast between injection zones, (2) presence/absence of shale barriers between injection zones, and (3) treatment volumes, among others. This paper presents the results of these simulations and the impact it has on hydrocarbon and water production and the overall profitability of a particular field. In addition, the field implementation of this technology in injection wells is presented.
Best Practices for Candidate Selection, Design and Evaluation of Hydraulic Fracture Treatments
Authors: Martin A. N. , Economides Michael J. 
Published: July 2010

AbstractHydraulic fracturing is a well-established completion technique, most notably in the tight and unconventional gas reservoirs of North America. Although still not nearly as prevalent, fracturing is the completion method of choice throughout the world, providing unparalleled contact between the reservoir and the wellbore. Placing a fracture means that it takes less energy to move the oil or gas from the reservoir to the wellbore. Flow rates are increased dramatically and reservoirs can be depleted to significantly lower pressures prior to abandonment. The process is accomplished by physically breaking the formation apart with extreme pressure and then placing a highly conductive and crush-resistant material ("proppant") inside the fracture. Subsequently, oil and gas will flow through the "propped" fracture and into the wellbore. Because the propping material has a permeability that is orders of magnitude greater than the formation, virtually all flow passes from the reservoir into the fracture and then along the fracture into the well. The hydraulic fracture length can reach significant distances into the formation, providing the inflow area that is essential to the production of gas from tight and unconventional formations, although remarkable results can also be achieved from medium- and high-permeability reservoirs.Although fracturing is often perceived as a technique for low-permeability reservoirs or remediation of mature fields, the best results are achieved from the best wells. One 100-md oil reservoir, effectively fractured, will produce the equivalent of 20 to 30 massive fracture treatments in 1-md reservoirs - and this factor increases to 50 to 70 for gas wells, due to the mitigation of turbulence within the reservoir.This paper is concerned with the processes of candidate selection, treatment design and treatment evaluation, and in particular with the best practices that help optimise these procedures, including measurements that make fracturing more successful, wellbore design, treatment design techniques and materials selection. Finally, the paper will consider how these processes may subsequently evolve.
Novel Approach to Mitigate Gas Production in a High GOR Carbonate Reservoir With Drilled Wells—Case Study
Authors: Chekani Mitra , Bagherpour M H. , Alavi M.. , Kharrat Riyaz 
Published: July 2010

Abstract
Improving oil production is one of the most challenging subjects in carbonate reservoirs, especially in the case of thin formations when reservoir pressure is close to saturation pressure with undesired well locations. In this study water injection was used to mitigate gas production in a thin reservoir with high gas oil ratio for the purpose of optimizing oil production.
The studied field is a cretaceous oil bearing reservoir composed of tightly packed limestone characterized by high porosity but poor permeability with a thickness of 55-65 meters throughout the reservoir. The matrix permeabilities and porosity are in the range of 0.01-150md and 5-35 percent respectively. The oil gravity is 21.5 degree API and reservoir pressure of 1700psia which is close to bubble point pressure of 1492psia. The produced wells were drilled in top layers of the reservoir.
A full field model was constructed to determine the optimal production strategy and applied reservoir management with available produced well locations. Two possible scenarios; namely, natural depletion and water injection were compared. Results indicated that water injection yields better recoveries than natural depletion. Different scenarios of injection well location, well orientation and mechanism of injection were considered.
Horizontal injection and production wells located at same layer were found to maintain reservoir pressure, prevent gas production, and increase oil recovery. Depleted regions near the producers were found to play a major rule on the success of the project. The enhancement of oil recovery was improved to 37 percent in the case of water injection with the implementation of proper reservoir management.
Production Enhancement Through Integrated Asset Modeling Optimization
Authors: Couët B.. , Djikpesse H.. , Tonkin T.. , Wilkinson D.. 
Published: July 2010

AbstractGas lift optimization is often used to enhance production of mature oilfields consisting of multiple reservoirs. For increased efficiency, several of those reservoirs often share the same surface processing facilities. In such context, we wish to find the optimal allocation of gas lift over an entire network of wells and pipelines, while accounting for the constraints imposed by the reservoir operating conditions. The latter may include a limited amount of commodities that can be processed or a limited amount of available lift gas per unit of time.Such engineering optimization problems are extremely difficult to model and to solve efficiently because they involve non-smooth models and are subject to constraints that might be simulation-based and as costly to compute as the objective function. Traditionally, they are solved using either penalty methods, which aggregate objective functions and all constraint evaluations, or classical lexicographic ordering, which evaluates all constraints simultaneously. While those techniques might be appropriate for computationally simple constraints, they could exhibit inefficiency when evaluating simulation-based constraints like the ones encountered in production optimization.In this modeling study, we describe a cost-effective approach to perform such optimizations. An adaptive proxy is used to replace the original constraints and objective function calculation, and a novel sequential lexicographic ordering approach is used to handle the constraints: the linear constraints take precedence over nonlinear constraints and simple nonlinear constraints take precedence over simulated-based ones, which, in turn, take precedence over objective function values. The proxy is periodically validated against the original function to maintain consistency. The methodology and two oilfield-production optimization examples involving oil and gas separation are described. These serve to demonstrate that the proposed method is more efficient than the traditional ones.
Combining and Customizing Technologies for Perforating Horizontal Wells in Algeria
Authors: Addoun Mohammed , Chisholm Ken , Ottolia Davide , Gama Cesar , Cosentino Renato , Dozoul David , Annibaldi Alessandro 
Published: July 2010

Abstract
Alternatives for perforating a horizontal well to maximize well potential vary according to equipment availability and requirements. In a rigless operation in Algeria, the combination of orienting the perforations upwards and shooting multiple small intervals instead of the whole horizontal section while maintaining an accurate depth control was the biggest operational challenge of the project. The final design customized new technologies, including dynamic underbalance perforation, addressable switches, and the use of premium deep-penetrating shaped charges. The results were satisfactory, and the well, which was perforated in two stages, currently produces 2,000 m3/day crude oil from both the toe and heel sections.
Execution of the rigless, electric-line-equipped coiled tubing perforation in the horizontal well included aligning the charges to the upper side of the horizontal section to avoid salting and to prevent gun debris from falling down into the well, maintaining the debris inside the gun carrier. Several laminated sections out of the 600-m total horizontal section were selected, and accurate depth measurement and correlation were necessary to perforate only the cleanest 200 m.
This paper provides the operational sequence and discusses alternative conveyance methods available in the industry.
Scale Buildup, its Detection and Removal in High Temperature Gas Wells of Miano Field
Authors: Shar Amjad Hussain , Ahmad Tofeeq , Bregar Udo B 
Published: July 2010

Abstract
Scale deposition, either in the formation, well bore or in the production facilities is a challenging problem in the petroleum industry.
Scale problems are generally associated with the deposition of inorganic minerals, such as calcium carbonate (CaCO3) and sulfates of calcium, strontium and barium. Downhole mineral scaling is either a product of self-scaling of the formation water (FW), (carbonate scale associated with changes in pressure and/or pH) or the mixing of incompatible waters (FW and injection water) with elements of other wellbore fluids or other minerals. The cost of scale buildup can be high, both in terms of deferred production and necessary remedial treatments.
Depending on the nature of the scale and the fluid composition, the deposition can take place within the reservoir, near the wellbore perforation tunnels which causes formation damage, or in production facilities subsurface and on surface with severe operational problems.
The Cased Hole Gamma Ray measurement has been proven quite effective to detect the presence of scale, due to radioactive content proven by the Scale XEM/EDAC analysis. The Scale solubility analysis has proven more than 95% of the sample, are soluble in 10%-HCl based acid.
Finally, the two case studies of Miano field have brought a new game changer for operations, to enhance the gas production. It is based on historical well observation, since no water production had been observed at the surface in one of the case study, so Scale was not considered to cause the production decline. Therefore the method of Cased Hole Gamma Ray measurement can be in some cases the only indication of scale build-up if other indicators are missing. Furthermore it’s also an effective method to prove scale build-up inside perforations if hole is fully accessible.
This paper describes the buildup of scale, its detection and its successful removal with coiled tubing in high temperature gas wells of Miano Field. Furthermore it will show some lab results, the execution and evaluation the results of a successful operation, which resulted in a restoration of high productivity.