bluuebunny/crossref_metadata_2025_split huggingface dataset:
Influence Of Drill-In Fluids Composition On Formation Damage
Authors: SÁnchez Erna , Audibert-hayet Annie , Rousseau Lionel 
Published: December 2007

Abstract
Drill-in fluids are generally water-based muds containing a viscosifier, a fluid loss reducer, salts and sized calcium carbonate particles. Formation damage mechanisms induced by the use of water based mud formulations (WBM) have been extensively studied and correspond to different phenomena such as water trapping, polymer adsorption and retention, and particle plugging. In this paper, a detailed study was carried out on the behaviour of scleroglucan based formulations generally proposed for high temperature zone and/or high permeability reservoirs. In addition, a classical xanthan based mud was prepared and the performances of xanthan and scleroglucan containing formulations were compared. This work covers not only the effect of the fluid composition, including the presence or not of drilled solids but also the filtration conditions such as shear rate and temperature. Filtration curves obtained under static conditions can be related to the rheological behaviour and thermal stability of the biopolymer used as a viscosifier. These curves are not related to the solid content of the mud. Under dynamic conditions, the filtration curve strongly depends on the aggregation tendency of the scleroglucan sample.
Mud filtrates have been characterized by multi angle laser light scattering coupled with size exclusion chromatography (SEC/MALLS). Characterization of the composition of the filtrate as well as the determination of the polymer molecular weight distribution, is very important to understand the formation damage tests performed on high permeability cores under downhole saturation conditions. Also, both the cake permeability and structure obtained by cryo SEM helped to understand the damage mechanisms observed with such formulations.
Optimized Drill-In Fluid Leads to Successful Open Hole Gravel Pack Completion Installation in Unconsolidated Reservoirs – Case History
Authors: Cobianco S. , Pitoni E. , Ricci P. N. , Galli M. 
Published: December 2007

Abstract
In this paper the designing process and the development work involved in the optimization of the drilling and completion fluids and their subsequent successful application in a highly deviated gas well recently completed in the South of Italy is reported. The most suitable fluid for drilling and underreaming operations was identified by an extensive laboratory study on the basis of the reservoir characteristics: temperature, estimated pore pressure gradient, effective permeability and sand control completion type. Two nondamaging fluid formulations were proposed: an environmental friendly formate-CaCO3 system and a conventional calcium chloride-CaCO3 formulation. For both these fluids the most suitable viscosifier, effective fluid loss reducer and appropriate particle size distribution of the bridging solids had been investigated and identified in the laboratory. Coreflooding tests showed similar fluid loss properties and return permeability results for both the formulations, but different trends had been observed during backflow as far as the removal of the filtercake and the lift-off pressure are concerned. Other considerations regarding the use of the expensive heavy formate-based brine in high permeable sands where massive fluid loss can be experienced led the selection of the CaCl2-formulation, even for drilling and completion.
In the field, all drilling and completion phases proceeded as planned and no fluid losses were recorded while drilling, underreaming and gravel packing, confirming the good work carried out in the laboratory. No matrix stimulation treatments were performed for clean up and expected gas rate was soon overcame by the well.
Consideration of Damaged Zone in Tight Gas Reservoir Model with Hydraulically Fractured Well
Authors: Behr Aron , Mtchedlishvili George , Friedel Torsten , Haefner Frieder 
Published: December 2007

Abstract
The paper shows a way to provide a detailed description of conditions in the hydraulically damaged fracture environment after closure and how to integrate it into a reservoir simulation model.
A special model initialization algorithm was developed and realized in a support tool to make possible the computing a post-fracture performance in tight gas formations by a reservoir simulator. The input represents the treatment schedule of the fracturing process and some results produced by commercial fracturing packages or geophysical measurements.
To represent the fracture geometry and properties, the information about the distribution of the proppant concentration in the fracture as well as fracture width variation is translated into the permeabilities and porosities of the fracture gridblocks. To determine the fracturing fluid saturation in the invaded zone, a new approach was derived to imitate the fracture propagation at a fracturing period under consideration of the leakoff processes. The penetration of the fracturing fluid into the matrix was modeled by Buckley-Leverett equations for two-phase non-miscible displacement with boundary conditions provided by a classical leakoff theory.
The approach is illustrated with a simulation model prepared to the analysis of the cleanup process in a damaged fractured well within a Rotliegende tight gas formation in North Germany.
A Decline Curve Analysis Model Based on Fluid Flow Mechanisms
Authors: Li Kewen , Horne Roland N. 
Published: December 2007

AbstractDecline curve analysis models are frequently used but still have many limitations. Approaches of decline curve analysis used for naturally-fractured reservoirs developed by water flooding have been few. To this end, a decline analysis model derived based on fluid flow mechanisms was proposed and used to analyze the oil production data from naturally-fractured reservoirs developed by water flooding. Relative permeability and capillary pressure were included in this model. The model reveals a linear relationship between the oil production rate and the reciprocal of the oil recovery or the accumulated oil production. We applied the model to the oil production data from different types of reservoirs and found a linear relationship between the production rate and the reciprocal of the oil recovery as foreseen by the model, especially at the late period of production. The values of the maximum oil recovery for the example reservoirs were evaluated using the parameters determined from the linear relationship. The results demonstrated that the analytical decline analysis model is not only suitable for naturally-fractured reservoirs developed by water flooding but also for other types of water drive reservoirs. An analytical oil recovery model was also proposed. The results showed that the analytical model could match the oil production data satisfactorily. We also demonstrated that the frequently-used nonlinear type curves could be transformed to linear relationships in a log-log plot. This may facilitate the production decline analysis.
Resin Coated Prepacked Sand Control Liner
Authors: Lombard Michael S. , Scott Gregory D. , Swanson Glenn S. 
Published: December 2007

Abstract
A novel and simple sand control technology has been developed and field tested featuring a prepacked liner consisting of thermosetting resin coated sand grains bonded by heat onto a perforated steel base pipe to form a solid, porous, and permeable cylindrical sand liner that can be installed into a wells requiring sand control. The Resin Coated Prepacked Sand Control Liner is a cost effective tool that can be applied to a variety of wellbore situations requiring remedial or primary sand control. The liner does not use wire wrapping and is constructed using standard oil field tubulars and commercially available thermosetting resin coated sand. The liner fills a need in certain sand control situations that cannot be solved using conventional technology. The Resin Coated Prepacked Liner is used with and without secondary gravel packing, depending on the well and reservoir conditions. The Resin Coated Prepacked Liner is currently installed in one well in the Long Beach Field, Southern California as a field test in a problem well that has historically experienced wellbore sand accumulation and repeated pump failures. Since installation in June 2002, the well has been sand free with an unexpected increase in oil production.
Binary Corrosion Inhibitors Offer Improved Corrosion Control
Authors: Zaid Gene H. , Sanders Donald W. 
Published: December 2007

Abstract
An improvement has been made in anti-corrosion chemicals for oilfield use. A binary corrosion inhibitor has been patented and field proven which combines an epoxy resin and an amine curing agent. The proper application of this unique combination of chemicals forms a bond with the oxide film present on downhole metal surfaces. The result is a corrosion inhibitor barrier that is more tenacious than conventional polar filming amines, reducing application frequency and labor costs, and even more importantly, downhole failures. The binary corrosion inhibitor is also an improvement over and is more versatile than other epoxy-amine products.
Discovering The Elusive Source of Water in the Mene Grande Field
Authors: Herring T. , Gomez H. , Oriozabala G. , Masaccese D. 
Published: December 2007

Abstract
The Mene Grande field has been producing since the early 1900s. Water production has been observed since the beginning with a slow steady increase in field water cut, which is currently at 40%. The watercut is repeatedly observed to decrease with increasing oil production and increase with decreasing oil production. This phenomenon can be repeated within a single well multiple times. Another typical production behavior of the Mene Grande Field is a double decline in production rate when plotted on semi-log paper much like a two layer system.
The current study seeks to offer an explanation for this unusual reservoir behavior with a focus on integrating production data, and quality control of the geostatistical model using pressure transient analysis, material balance and variogram analysis. Detailed well models have been used to guide the geostatistical input by history matching selected transient tests including the very characteristic derivative response of this heterogeneous fluvial reservoir. Additional quality control has been obtained by matching variograms from pseudo wells in the inter-well area. These variograms have both highlighted flaws and suggested remedies to the previous modeling methodology.
The overwhelming conclusion is that the dominant source of water production is the depletion of the reservoir shale. This conclusion also provides significant insight into the reservoir characterization and communication levels within the field. The results have had a direct impact on completion strategies and IOR evaluations.
The results of this work demonstrate how the use and combination of traditional analysis can be integrated to enhance the reservoir characterization process. The methodology applied during this work can easily be included in similar reservoir characterization projects.
To our knowledge significant water production and pressure support has not previously been linked to the depletion of reservoir shales within oil reservoirs. It is however felt that this mechanism offers an explanation for many of the Costal Bolivar fields, which tend to have similar water production profiles over the long term.
An Economic Appraisal of Hole Cleaning Using Hydraulic Horsepower and Jet Impact Force
Authors: Wright James , Chukwu Godwin A. , Khataniar Santanu , Patil Shirish 
Published: December 2007

Abstract
One of the effective steps in reducing the operating costs for drilling an oil/gas well is to optimize the energy used at the mud pumps. Mud pumps are massive pieces of equipment and they serve as integral part of the cuttings removal system. A variety of hydraulic optimization designs are available, however, in this study, the efficiency and cost effectiveness of two methods namely; Hydraulic Horse Power and Jet Impact Force are compared. Both of these methods have a fundamental objective of maximizing the available hydraulics to provide optimum hole cleaning.
This paper presents an economic comparative analysis of using the Hydraulic horsepower and the Jet impact force for optimizing hydraulics for hole cleaning. The evaluation and analysis of parasitic pressure losses and the impact on optimization using both methods are presented. By determining the optimum bit nozzle sizes, the horsepower requirements and the energy cost for each method are determined and analyzed.
Rate Forecasting of a Mature Waterflood Using Fractional Flow Theory and Hyperbolic Decline Curve Analysis, East Wilmington Long Beach, California
Authors: Al-Sharif S. , Rael E. 
Published: December 2007

Abstract
THUMS Long Beach Unit has developed and maintained a strong waterflood in the Ranger reservoir. Historically, Log water-oil ratio (WOR) vs. cumulative produced oil (Np) relationships have been used to predict field oil and water rates over time. An assumption made when forecasting by Log WOR vs. Np is that the total liquid rate remains constant over time. This assumption has proved to be inadequate in accurately modeling the performance of the flood with respect to total fluids production. THUMS has experienced an increase in liquids production per day on a well-by-well basis and on a total Ranger base performance level over time. As redevelopment of the waterflood progresses, a more accurate method of predicting total fluids production is required for facility planning, management of future lifting costs, and optimization of reservoir performance.
This document discusses the methodology applied by THUMS Long Beach Unit to forecast oil and water rates over time. The methodology uses a combination of predicting oil rates by hyperbolic curve fitting, and water rates by fractional flow (fw) relationships. Ranger reservoir forecasting consists of subdividing the Ranger into key forecast areas. Once the areas have been defined, a reservoir analysis is performed to determine current saturations for each producing interval, based on hydrocarbon pore volumes injected to date (HPVI). A log WOR vs. Np relationship is established based on the theoretical fractional flow relationship. Using Arps decline variables to hyperbolic best-fit base oil production for the areas yield an Np vs. Time relationship. The Np vs. Time relationship is then applied to the theoretical Log WOR vs. Np curve specific for that forecasting area. The result yields a more reliable water forecast, which honors theoretical and observed inclining water rates over the producing field life.
Analytical Method to Predict Waterflood Performance
Authors: Lerma M. K. Val 
Published: December 2007

Abstract
It’s difficult to predict waterflood performance in heterogeneous, layered reservoirs. Fractional flow analysis provides a fundamental approach to the problem. Each layer can be analyzed and then a composite formed to model the reservoir’s performance. Various data sources can be used to ensure the validity of the analysis. This study incorporated information from the Inglewood Oil Field, including injection profiles, core data, tracer data, log data and production data to model waterflood performance on a layer by layer basis. A production historical match was then made to validate the fractional flow analysis. This information can now be used to calculate the expected production schedule and ultimate oil recovery, and the timing necessary for that recovery from each layer. Finally, this information forms an economic basis for well drilling and workover activities to allow maximum waterflood sweep efficiency.
Cost/Benefits of Horizontal Wells
Authors: Joshi S. D. 
Published: December 2007

Abstract
This is a summary of state of the art horizontal well technology and a review of the economic benefits of horizontal wells. The paper describes various reservoir applications of horizontal wells from primary recovery to EOR applications. The paper includes field examples of different applications.
Although horizontal wells have been drilled as early as 1927, the major thrust of drilling horizontal wells started in 1980. Initial wells were short length wells (about 250 ft. long wells). In 1985, the first medium radius horizontal well was drilled using a down-hole mud motor. Since then, using horizontal wells has become a common practice. Today, the medium radius drilling technique is the most commonly used drilling method.
In the U.S., the majority of applications are in low permeability, naturally fractured, carbonate reservoirs. However, in California, Alaska and Gulf of Mexico most of the wells are drilled in clastic reservoirs. Similarly, outside the U.S., most of the horizontal wells are drilled in clastic reservoirs.
Horizontal wells have been used to produce thin zones, fractured reservoirs, formations with water and gas coning problems, waterflooding, heavy oil reservoirs, gas reservoirs, and in EOR methods such as thermal and CO2 flooding. The paper includes field examples with cost benefit analysis for various applications.
Through Tubing Rotary Drilling and its Associated Cementing Challenges: A North Sea Experience
Authors: Queiros João G. R. , Benoit Vidick , Cochran Jamie 
Published: December 2007

Abstract
The cementation of any casing string is an integral part of well construction. The main objective of primary cementing is to provide complete and permanent annular isolation from mechanical and chemical stresses during drilling and production stages of the life of the well.
Through tubing rotary drilling (TTRD) technology presents its own challenges to cementing design. The management of the equivalent circulating density (ECD), typically at its highest levels during the final stages of the cement slurry displacement, is a critical parameter of the fluids design process. The use of bi-centre drilling bit design, which achieves a larger open hole size than the pass-through diameter, introduces centralization difficulties and add complexity to the removal of the drilling mud prior to cementing.
The accepted cementation approach for TTRD wells is to formulate low rheological fluids such that, maximum advantage can be taken from the annular velocities for mud removal efficiency.
By challenging the common design practices a design was proposed that combined low and high rheology fluid properties to achieve the objectives set out for the cementing operation of the 2 7/8 inch liner.
Lessons Learnt and Experiences Gained During Two Years of Field Monitoring, Data Integration and Reservoir Management: A Case History of the Mauddud Waterflood, North Kuwait
Authors: Chetri H. B. , Al-Anzi Ealian , Al-Rabah Abdullah , Al-Dashti Hussain , Al-Mutawa Majdi , Chakravarthi Ravula , Brown Matthew , Isby John , Clark Alan 
Published: December 2007

Abstract
The Sabiriyah Mauddud limestone of North Kuwait is a super giant depletion drive oil reservoir. It is undergoing massive development efforts, with a planned enhancement in oil production through phased pattern water flood. The Phase1 development addresses the crestal area (50 km&lt;sup&gt;2&lt;/sup&gt;) of the structure, which was the focus for development efforts in the past. The Phase2 development consists of all remaining peripheral acreage (200 km&lt;sup&gt;2&lt;/sup&gt;), with immense reservoir rock & fluid uncertainties, leading to the identification of reservoir segments for re-appraisal through drilling & testing of new wells.
Re-appraisal work, along with enhanced fluid description, led to the conclusion that a large segment within the Ph2 area, originally considered as a regime of light oil - turned out to be viscous oil. This helped immensely the ongoing Full field dynamic modeling and development planning for this multi billion-barrel reservoir. This also led to the initiation of a Water flood pilot with Non-Conventional Wells in the poorer Ph2 area.
Two years of dynamic performance from producers and injectors located in the Ph1 area enhanced the understanding of the reservoir dynamics. Time lapsed monitoring of static reservoir pressures at key wells during the ongoing water flood, coupled with isochronal Pressure surveys during reservoir shut-downs and RFT data from newly drilled wells in the area during the post injection period, helped to confirm the pressure connectivity across the reservoir and the water flood response. Pressure transient and Production tests gave valuable insights into the well performance and reservoir architecture. In addition to monitoring and maintaining the Seawater injection system at high efficiency level, the regular program of water analysis at the pattern producers provided inferences on water breakthrough trend. Integration of the dynamic data with Production logs & FMIs led to the identification of speed zones with high permeability. This helped to fine tune the Static model.
This paper documents the case history of Waterflood management in a super giant carbonate reservoir and the challenges that had to be met.
Use of Finite Difference Sector Model to Analyse Well Test in the Ormen Lange Gas Field
Authors: Irfan Ahmed 
Published: December 2007

Abstract
The Ormen Lange gas field is intensely faulted which may lead to poor reservoir communication. More than thousand faults have been interpreted and included in the simulation model.
Two exploration wells were tested. The first well test, 6305/7-1 in 1998, showed no boundaries but it is located in a less faulted area. The second well test in mid 2002, well 6305/4-1, showed sealing flow barriers on the pressure data. The objective of this paper is to discuss the result and the methodical interpretation of 6305/4-1 well test in detail and illustrate the importance of numerical finite difference test simulation compared with the analytical interpretations.
Well 6305/4-1 was drilled and tested within a well-defined fault polygon in the North Western flank of the structure. The main objective was to obtain information on fault sealing capacity and to detect possible pressure depletion.
An analytical test interpretation was performed, and the best test match resulted in a no-flow boundary wedge shaped model. The analytical test interpretation gave a good match, but was not able to answer the questions about the geometry and extension of the sealing faults. The numerical finite difference simulation model allows different fault combinations, which are based on realistic geophysical and geological models. A very fine gridded sector model was established, upscaled from a full 3D geological reservoir model. The gridding and Local Grid Refinement (LGR) was carefully investigated and designed.
A large number of numerical test simulations were run, with different fault sealing combinations and fault properties. The best test match suggested that fault might be closer or have different geometry than in the reservoir model.
Reprocessed seismic data improved the data quality and gave an improved imaging of the faulting on the structure. Based on that, fault geometry in the simulation model was updated. This model was further used in obtaining a perfect time/distance match between simulated and real data.
The extensions of sealing faults were thoroughly examined, and a good test match was obtained. Simulation results suggested that three of the faults have to be sealing in vicinity of the well and down-flanks, while a large part of the polygon must be open up-flanks. The results improved and simplified the field development and reservoir management scenarios. These results indicated that faults are open up-flank, and that the gas filled Ormen Lange reservoir is in pressure communication, as also documented by the static pressure data in all the wells.