bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stimulating High-Water-Cut Wells: Results From Field Applications
Authors: Arangath R. , Obamba J. F. , Saldungaray P. , Malonga H. 
Published: December 2007

Abstract
A common scenario in many mature oilfields is to have most of the wells producing hydrocarbons with high water cuts. These wells are commonly not considered as good candidates for matrix stimulation. Water based treating fluids would enter preferentially into zones with high water saturations leaving oil zones untreated with a final result of increasing overall water production. However if the water production mechanism is understood and the appropriate fluids are selected then stimulating producer wells with high water cuts can be a rewarding operation. The treatment can be carried out while providing favorable economics to the entire operation.
The key fluid for treating high water cut wells is a Viscoelastic fluid that provides self-diversion from water to oil bearing formations. At the same time this same fluid can be used, on long intervals, to divert matrix stimulation treatments from stimulated to un-stimulated intervals or from high permeability intervals to low permeability intervals. These features are unique and inherent to its nature and the particular break mechanism making them suitable for selective placement and uniform zone coverage even for bull heading operations.
The paper presents the experiences with this Viscoelastic fluid used in nine different mature producer wells with pre-treatment water cuts ranging from 32% to 94%. One additional case in presented on a newly drilled producer that was perforated and completed very close to a water zone that was successfully stimulated without any increase in produced water cut. Treatments presented include both cases in which fluids are bull-headed and placed through coiled tubing. The case histories included in the paper illustrate the pre and post treatment production results obtained. All are characterized by the fluid usage contributing to the stimulation being uniformly conveyed across the oil-bearing portion of the reservoir and away from the watered out intervals.
A description of the well candidate selection process, formation damage identification and the remedial treatment design, execution and results is briefly discussed along with the economic impact that such treatments offer to mature oilfields.
A Case Study of Offshore Production Control Through Advanced Process Automation
Authors: Bumatay R. , Sankaran S. , Mijares G. , Vazquez-Esparragoza J. J. 
Published: December 2007

Abstract
The Malampaya Deepwater Gas-to-Power project, the single biggest industrial investment to date in the Philippines, supplies clean, environment-friendly fuel to service 30% of Luzon's power generation requirements. Subsea wells and a manifold gather gas and liquid and control the flow to a shallow water platform. Here, gas and condensate are separated before transporting dry gas through a 504 km long pipeline to an onshore gas plant. A key challenge of the Malampaya offshore facility is to maintain a smooth, continuous operation under varying demands of gas delivery from the onshore gas plant, which often leads to slugging at low flow rates.
This paper focuses on the successful implementation of Halliburton's advanced process automation solutions to improve operation of the offshore platform. The applied solutions include advanced control applications to better control production and the operation of the methanol recovery column and an alarm management system to improve the effectiveness of the alarm system that enables the operators to better respond to abnormal operating conditions.
A core principle of the advanced control application for production control is to maximize the use of topside installed capacity to better handle production rate changes while maintaining the stability of the export gas compressor and the liquid processing equipments, particularly at low production levels.
As part of the implementation of the advanced control applications, some advanced regulatory control improvements to the compressor systems were required to automate speed control for the compressor and to reduce recycling.
The alarm management system allows regular analysis of alarm activity and identifies "bad actors". The project included the execution of a rigorous alarm rationalization procedure, which reduced the number of unnecessary alarms considerably and allowed the operator to focus on the needed areas of action during abnormal operation.
Significant tangible and intangible benefits have been identified as a result of the implemented solutions. These benefits included increases in production, stemming from improved process stability, and reduction of environmental risks from the methanol column operation and better alarm reaction times. This case study highlights the value that advanced process automation can bring to the upstream industry.
A New Correlation Predicting the Formation of Iron Sulfide Precipitation in Wastewater Disposal Wells
Authors: Bahadori A. , Zeidani K. 
Published: December 2007

Abstract
Scale formation and well plugging due to the incompatibility of injected wastewaters is a critical field problem in wastewater disposal wells. When different wastewaters are mixed it is necessary to evaluate their compatibility prior to the injection in disposal wells. The individual wastewaters may be quite stable at all system conditions and present no scale problems. However, once they are mixed, reaction between ions dissolved in the individual wastewaters may form insoluble products that cause permeability damage in the vicinity of the wellbore.
In this paper, the composition of different wastewaters that were collected from southwest Iranian desalting plants disposal wells were analyzed critically. Laboratory studies as well as field experience has shown that formation damage in wastewater disposal wells may occur mainly due to the conception of Iron Sulfide in the case of mixing a wastewater which contains Iron ions with a wastewater containing H2S. A new correlation is developed estimating the critical concentration of Iron ions, Fe(2+) (ferrous ion), which will stay in solution at various pH values and a wide range of H2S concentration in crude oil desalting plants disposal wastewaters. This correlation eliminates the need for compatibility assessment, which is usually assessed either by solubility calculations or by experimental testing, for water mixtures that contains Iron ions and dissolved H2S. Finally, a real case field problem was analyzed and based on the correlation's results three different potential solutions were recommended for further field trial implementation.
Intelligent Integrated Dynamic Surveillance Tool Improves Field-Management Practices
Authors: Al-Fattah S. M. , Dallag M. M. , Abdulmohsin R. A. , Al-Harbi W. A. , Issaka M. B. 
Published: December 2007

Abstract
This paper describes solutions developed using a dynamic surveillance tool to automate several workflow processes of the reservoir management, production engineering, and R&D Center at Saudi Aramco. The objective is to provide improved efficiency in field management practices, while enhancing collaboration between reservoir and production engineers; ultimately resulting in improved decision-making process.
The solutions provided include a combination of smart tools and automated workflows designed to improve reservoir management and surveillance processes. A candidate recognition system was developed to identify and flag problem wells that require immediate remediation. As new production and injection data become available, the system that is linked to the corporate database can automatically display these data for fast and rigorous validation. In addition, a formation damage indicator function is also calculated using field data and mapped to spot production problem areas and identify damaged wells. A daily surveillance tool, which compares the performance of individual wells to the average performance of a group of wells, is also provided to allow the reservoir and production engineers to easily identify underperforming wells, promptly intervene, and recommend best completion practices. Benefits include efficient well management and cost avoidance resulting from early intervention and remediation, while avoiding full-scale problem resolution.
Another dynamic surveillance tool was designed and views were developed to provide online access to the hydrocarbon phase behavior and petrophysical data for the R&D scientists and reservoir engineers. The tool allows integration of the hydrocarbon phase-behavior data and comparison of petrophysical data with historical production/injection data and production well logs, resulting in enhanced analysis, production optimization and data validation. Additional benefits of the smart tools and automated workflow processes include considerable timesavings, with pertinent data being automatically updated, validated and used in the analysis, leading to improved efficiency in field management practices.
SSC Resistance of QT-900 and QT-1000 Coiled Tubing
Authors: McCoy T. H. , Thomas J. 
Published: December 2007

Abstract
Laboratory sulfide stress cracking (SSC) tests were performed on specimens taken from QT-900 and QT-1000 coiled tubing (CT) test strings in an attempt to define zones of acceptable sour service. Acceptable pH-PH2S zones of service for QT-900 CT were proposed in SPE 93786.1 This paper presents additional QT-900 CT test data to further refine acceptable zones of service, with and without use of a chemical inhibitor. In addition, SSC testing was undertaken on QT-1000 CT. The SSC tests on QT-1000 CT were performed in manner similar to that conducted on QT-900 CT, using acidified aqueous solutions with H2S partial pressures ranging from 0.00345 to 100 bars and pH from 3.5 to 6.5, with and without inhibitor. Both as-milled and pressure-cycled tubing was tested. Test specimens were taken from parent metal and bias weld locations. The test data was used to construct acceptable zones of service on a pH-PH2S diagram.
A Comprehensive Bit Hydraulics Model for Gasified Drilling Fluids
Authors: Dogan H. A. , Gucuyener I. H. , Ozbayoglu M. E. 
Published: December 2007

Abstract
Determination of pressure drop at the bit is one of the major concerns for establishing proper hydraulic design. Little has been known about pressure drop estimation at the bit for single phase muds, and even less is known about gasified fluids. The aim of this study is to fulfill this gap in the literature. Although there are numerous studies on this subject available in the literature, they are either valid for high gas flow rates or developed using very strong assumptions. The proposed theory, which is valid for both sonic (critical) and subsonic (sub-critical) regimes, is based on the solution of the general energy equation for compressible fluid flow. Unlike the existing models in the literature, the proposed model takes the change in kinetic energy, compressibility factor, and internal energy terms into consideration. Moreover, the model uses "a mixture sound velocity" approach for determination of the sonic boundary of the fluid. Based on the proposed model, a computer program is developed for calculating the pressure drop through a nozzle at subsonic flow region. The performance of the proposed model is tested by comparing the model results with existing models estimations using realistic field data. It is observed that, as much as 9% difference occurs between the results of the proposed and existing models.
Drilling Optimization at the Aloctono Block in Venezuela With the Utilization of Latest Technologies in Impregnated Bits and Turbines
Authors: Botelho R. , Barreto J. , Bello S. , Anato W. , Uzcategui G. 
Published: December 2007

Abstract
The Aloctono Block at northern Monagas state in Venezuela is one of the most difficult drilling challenges in this region. It basically consists of a Cretaceous geological structure overlaying younger formations, characterized by heterogeneous lithology and presence of extremely abrasive and compacted formations with fine to very fine sandstone grains, in which the compressibility can be higher than 40,000 psi.
Conventionally this geological column has been drilled with packed and/or pendulum assemblies using roller cone and PDC bits, so that the following problems take place: difficulty of well verticality control, excessive wear of drill string components, poor bit performance with short runs, low penetration rates and excessive bit wear, leading to higher risks of cone loss in roller cone bits and the consequent fishing operations. This scenario generates high drilling costs, long well drilling time with lots of bit trips, drill string inspection and downhole tools replacement. For such reasons, a reevaluation of these conventional drilling practices, as well as the utilization of latest drilling technologies have a huge impact on time and costs reduction.
This work shows how the utilization of latest technologies in impregnated bits and turbines optimized the drilling performance of the Aloctono Block, reducing quantity of bits, trips and others, representing huge savings for the operator. One must note that other benefits were also accomplished, such as well bore quality and verticality control, reduction of surveys, no fishing operations and reduction of replacement and repair costs of drill string components.
Optimization of Tertiary Water-Alternate-CO2 Flood in Jilin Oil Field of China: Laboratory and Simulation Studies
Authors: Guo X. , Du Z. , Sun L. , Fu Y. , Huang W. , Zhang C. 
Published: December 2007

Abstract
Most of the low permeability oil reservoirs in Jilin oil field of China have reached their economic limit of production by waterflooding and even many wells have been abandoned due to low productivity. Interest in recovery enhanced technology of tertiary miscible or immiscible CO2 flooding is increasing in these low permeable reservoirs. In this paper, a laboratory study using a high-pressure PVT cell and a simulation study using full-field fully equation-of-state (EOS) compositional reservoir modeling were undertaken to optimize the design of a miscible or immiscible CO2 flood pilot project for the Xinli Unit in Jilin oil field. The laboratory study includes phase behavior analysis, asphaltene deposition assessment, and minimum miscibility pressure (MMP) determination in the CO2 corefloods. Based on building a full-field 3D geologic model and history matching waterflood performance, a preliminary CO2 flood reservoir modeling has been used to distinguish displacement mechanisms and reservoir performance of natural depletion, continued waterflooding, continuous CO2 and water-alternate-CO2. The simulation study and the pilot test showed water-alternate-CO2 after waterflooding is an effective method of improved oil recovery for the low permeability reservoir and it can appreciably reduce water production and enhance oil recovery. Simulation studies has also been completed to determine an optimal water-CO2 ratio, optimal CO2 slugs and optimal CO2 injection rate. The pilot operation is now well implementing according to above-mentioned study achievements. Future plans for water-alternate-CO2 optimization include continuation of performance monitoring to help optimize tapering strategy in order to enhance further oil recovery in the low permeability oil reservoir.
Approximate Pore-Level Modeling for Apparent Viscosity of Polymer-Enhanced Foam in Porous Media
Authors: Huh C. , Rossen W. R. 
Published: December 2007

Abstract
Foam is used in the oil industry in a variety of applications, and polymer is sometimes added to increase foam's stability and effectiveness. A variety of surfactant and polymer combinations have been employed to generate polymer-enhanced foam (PEF), typically anionic surfactants and anionic polymers, to reduce their adsorption in reservoir rock. While addition of polymer to bulk foam is known to increase its viscosity and apparent stability, polymer addition to foams for use in porous media has not been as effective.
In this pore-level modeling study, we develop an apparent viscosity expression for PEF at fixed bubble size, with the intention of better interpreting the conflicting laboratory coreflood data available. To derive the apparent viscosity, the pressure-drop calculation of Hirasaki and Lawson (1985) for gas bubbles in a circular tube is extended to include the effects of shear-thinning polymer in water, employing the Bretherton's asymptotic matching technique. For polymer rheology, the Ellis model is employed, which predicts a limiting Newtonian viscosity at the low-shear limit and the well-known power-law relation at high shear rates. While the pressure drop due to foam can be characterized fully with only the capillary number for Newtonian liquid, the shear-thinning liquid requires one additional grouping of the Ellis-model parameters and bubble velocity.
The model predicts that the apparent viscosity for PEF shows behavior more shear-thinning than that for polymer-free foam, because the polymer solution being displaced by gas bubbles in pores tends to experience a high shear rate. Foam apparent viscosity scales with gas velocity (Ug) with an exponent [−α/(α+2)], where a, the Ellis-model exponent, is greater than 1 for shear-thinning fluids. With a Newtonian fluid, for which α =1, foam apparent viscosity is proportional to the (-1/3) power of Ug, as derived by Hirasaki and Lawson.
A simplified capillary-bundle model study shows that the thin-film flow around a moving foam bubble is generally in the high-shear, power-law regime. Since the flow of polymer solution in narrower, water-filled tubes is also governed by shear-thinning rheology, it affects foam mobility as revealed by plot of pressure gradient as a function of water and gas superficial velocities. The relation between the rheology of the liquid phase and of that of the foam is not simple, however. The apparent rheology of the foam depends on the rheology of the liquid, the trapping and mobilization of gas as a function of pressure gradient, and capillary pressure, which affects the apparent viscosity of the flowing gas even at fixed bubble size.
Application of Horizontal Waterflooding To Improve Oil Recovery From Old Oil Fields
Authors: Westermark R. V. , Schmeling J. , Dauben D. L. , Robinowitz S. , Weyland H. V. 
Published: December 2007

Abstract
This paper discusses the results of the application of horizontal waterflooding technology to improve the recovery of oil from older fields. A multi-disciplinary approach combining geological interpretations, rock mechanics evaluations, reservoir simulation studies, and drilling technologies was employed. A range of reservoir conditions in which the technology is viable is discussed and the results of the field tests are presented.
The major focus has been on the shallow sandstone reservoirs in northeast Oklahoma and southeast Kansas. It has been demonstrated that additional oil can be recovered in several different reservoir environments in these older fields, by utilizing a combination of horizontal and vertical wells. Two previous SPE papers described the results of a Department of Energy (DOE) supported horizontal waterflooding pilot located in the Wolco Field, Osage County, Oklahoma.
The technology has continued to evolve over time. The key to assessing the potential for a horizontal well application is a thorough understanding of the reservoir description, including the oil saturation, depositional environment, reservoir pressure, permeability, and an evaluation of any prior production and/or injection. Other parameters include the length, spacing, positioning and orientation of the injectors and horizontal producers in the target zone. Use of rotary-steerable drilling equipment has made it possible to drill underbalanced, short-radius horizontal laterals at a low cost. Special procedures have been adopted to permit the transport of openhole logging equipment through the short-radius curve to the end of the lateral, providing a good description of reservoir properties and detecting the presence and orientation of natural fractures.
Results from several successful horizontal well projects are discussed. These include (1) two horizontal waterfloods in shallow Bartlesville sandstone reservoirs, (2) recovery from a rim of moderately heavy oil underlain by water, and (3) an application of horizontal waterflooding in a moderately heavy oil reservoir.
Mass Transfer and Gelation in Sandstone Cores of a Novel Water Shutoff Chemical
Authors: Castelijns H. J. , Pel L. , Huinink H. P. , Zitha P. L. J. 
Published: December 2007

Abstract
An innovative water shut-off chemicals was recently proposed. The chemical is soluble in oil without any chemical reaction and forms gel in the presence of water. When the chemical dissolved in oil is injected in the near well-bore formation it modifies selectively the two-phase flow properties in order to reduce the production of water. The gelation process involves the partitioning of the chemical from the oil phase into the water phase. Upon contact with water a heterogeneous (hydrolysis and condensation) reaction takes place between gelant and water, leading to the formation of a gel in the water phase.
Recently we have demonstrated that NMR imaging is a viable technique for visualizing and quantifying the above reactive mass transfer process in bulk and glass bead systems.1,2
Here we report a new core-flood experimental study consisting of the placement of the chemical dissolved in oil in Bentheim sandstone cores. NMR imaging and (T1 and T2) relaxation time measurements are used to monitor the reactive transport of the chemical in the core. The mass transfer of the chemical from the oil phase to the water phase is derived from the measurement of T1 related to the oil phase. The progress of hydrolysis and gelation is indicated by a decrease in T2 of the water phase.
Simops: Coiled Tubing in Parallel With Rig Activities
Authors: Torgersen K. I. , Weiss A. A. 
Published: December 2007

Abstract
This paper covers SIMOPs, SIMultaneous Operations, and describes the topic of doing well service operations in parallel with main rig activities. There are various descriptions for the term SIMOPs, but this paper focuses on doing well servicing operations with Coiled Tubing, CT, or Wire Line, WL, in parallel with drilling or other rig based operations from the main derrick.
SIMOPs have been performed for several years on some platform. However this is still a new innovation for others, and is often considered to be impossible due to various small platform limitations, such as: deck space, crane capacity, bed space, etc.
This paper highlights the potential upside of working multiple operations in parallel. The focus is on the challenges related to rigging up and operating within the limitations of the platform and rig. This is described through case histories, as examples of how solutions have been developed to perform a large scope of well services activities on rig less platforms in parallel with drilling activities through cantilever rig, from jack up rig.