bluuebunny/crossref_metadata_2025_split huggingface dataset:
Internal Breakers for Viscoelastic-Surfactant Fracturing Fluids
Authors: Crews James B. , Huang Tianping 
Published: December 2007

Abstract
Over the past two decades, viscoelastic surfactant (VES) fluids used for gravel packing, frac-packing and conventional hydraulic fracturing have primarily relied on external or reservoir conditions to break the fluid’s viscosity. Unlike polymeric fluids, no internal breakers have been used. Relying on external conditions to break VES fluid has been a point of contention and questionable, especially for dry gas applications.
This paper describes how new internal breaker technology has been developed that allows VES fluids to be broken into easily producible fluids, without the need for contacting reservoir hydrocarbons. The reservoir pressure required to produce VES fluid is no longer compromised: very little pressure or time is required when an internal breaker is present. Mechanisms for internally breaking VES viscosity are discussed. New internal breakers have been found to work over a wide fluid temperature and mix water salinity range, and have compatible with newly developed VES stabilizers and fluid loss control agents. Presented are laboratory results that compare VES fluids with and without an internal breaker. Rheological data is presented that show the performance of internal breakers in degrading VES fluid viscosity, in particular at low fluid shear rates. Core clean-up tests were performed at 150°F, using 3% KCl brine and nitrogen gas as the displacement (clean-up) fluid. The results show that use of an internal breaker significantly improves VES fluid clean-up. This paper also presents VES system compatibility and proppant conductivity results.
A New IMPSAT Formulation for Compositional Simulation
Authors: Haukås J. , Aavatsmark I. , Espedal M. , Reiso E. 
Published: December 2007

Abstract
A new IMPSAT formulation for compositional simulation is presented. The new formulation is based on explicit solution of variables that are isochoric, i.e., complementary to volumes, instead of explicit solution of phase mole fractions, which is the conventional IMPSAT approach. The paper focuses on performance of the nonlinear iteration and numerical stability.
The use of complementary variables in the new IMPSAT formulation makes the nonlinear system better conditioned. Consequently, fewer nonlinear iteration steps are required. The resulting speed-up more than compensates the added costs of introducing and using the isochoric variables.
The stability criterion introduced with the new formulation is in many cases significantly less conservative than the conventional criterion. However, for cases where there is little or no saturation change between the hydrocarbon phases, e.g., for retrograde gas condensate cases or single hydrocarbon phase cases, the difference between the criteria is insignificant.
The timestep sizes for which instabilities occur with the new and the conventional formulation are practically the same, and no oscillations have been observed unless both the new and the conventional criterion are violated. Consequently, the stability properties are similar, and the new criterion seems to apply to both the new and the conventional formulation.
Our conclusions are supported by numerical results.
Hydraulic Fracture Model Sensitivity Analyses of a Massively Stacked, Lenticular, Tight Gas Reservoir
Authors: Green Christopher A. , Barree Robert D. , Miskimins Jennifer L. 
Published: December 2007

Abstract
This paper critically assesses the importance of various inputs that are used for a common methodology to develop a simulator model of hydraulic fractures in geologically complex, fluvial, tight gas reservoirs. A planar 3-D fracture simulator is used with a fully coupled fluid/solid transport simulator. The geo-mechanical rock properties from logs (Young's modulus, Poisson's ratio and Biot's constant) and diagnostic mini-frac injection tests of individual sandstone reservoirs were investigated to assess their importance in developing a valid stress model.
The work describes the investigations using a model previously matched using both net surface pressure and micro-seismic/tiltmeter data. From these results it is possible to get a better understanding of how fracs grow and interact with complex fluvial reservoirs, allowing operators to better optimize field well performance and completion methods in these geologic settings. Additionally, the minimum critical data recommendations necessary to develop such a model have been identified and will aid operators in developing their data acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extrapolated to other similar geologically complex reservoirs world-wide.
Use of Nitrate or Nitrite for the Management of the Sulfur Cycle in Oil and Gas Fields
Authors: Voordouw G. , Buziak B. , Lin S. , Grigoriyan A. , Kaster Krista M. , Jenneman G. E. , Arensdorf J. J. 
Published: December 2007

Abstract
The production of sulfide by sulfate-reducing bacteria (SRB) in oil and gas fields causes problems including enhanced corrosion risk, reservoir plugging and deterioration of product quality. Injection of nitrate or nitrite stimulates heterotrophic nitrate-reducing bacteria (hNRB), which compete with SRB for oil organics, such as volatile fatty acids (VFA). Nitrate also stimulates nitrate-reducing, sulfide-oxidizing bacteria (NR-SOB), which lower sulfide levels. Nitrite is a strong and specific inhibitor of the SRB enzyme responsible for sulfide production, whereas nitrate does not inhibit SRB.
Hence, injection of nitrate or nitrite can prevent or remediate problems in the oil and gas industry caused by SRB activity, provided hNRB and NR-SOB are present.
A survey of 8 oil fields, 2 gas storage reservoirs and an oil storage tank indicated that SRB and hNRB were widely distributed, whereas the distribution of NR-SOB appeared more limited. The SRB and hNRB were able to use lactate, as well as VFA as electron donor for sulfate or nitrate reduction. However, the order of use of VFA components appeared to differ with acetate being used preferentially by hNRB and propionate and butyrate being used preferentially by SRB. The production of nitrite by hNRB and NR-SOB varied greatly with quantitative conversion of nitrate to nitrite (up to 30 mM) being observed in one case; the nitrite formed was then reduced further. Samples from a high temperature North Sea oil field had thermophilic SRB, but no hNRB or NR-SOB activity, causing sulfide production to be inhibited by nitrite only. Although nitrite appeared to react chemically with sulfide under these conditions, causing all nitrite to disappear within 100 h, the observed inhibition was long-lasting (&gt;500-1500 h). Hence, nitrite can be used successfully to control SRB activity in fields where hNRB and NR-SOB are absent.
In summary, it appears that many oil and gas fields contain hNRB and NR-SOB populations, which are activated upon injection of nitrate or nitrite, allowing sulfide remediation in situ. Characterization of these populations as described in this paper may allow prediction whether these injections will be successful and whether use of nitrate or of nitrite is preferred.
Fracturing Fluid for Low-Permeability Gas Reservoirs: Emulsion of Carbon Dioxide With Aqueous Methanol Base Fluid: Chemistry and Applications
Authors: Gupta D. V. S. , Hlidek B. T. , Hill E. S. W. , Dinsa Harpreet S. 
Published: December 2007

Abstract
High-quality emulsion of carbon dioxide (CO2) in aqueous alcohol-based gel (CO2 emulsion) was introduced into the Western Canadian Sedimentary Basin (WCSB) as a fracturing fluid in 1981. Since that time, the use of the fluid has been very successful, particularly in low-pressure, tight gas applications. The fluid has all the advantages of conventional high-quality CO2 foams/emulsions, with the added advantage of minimizing the amount of water introduced into the well.
The present paper will discuss a fluid that is an emulsion of liquid carbon dioxide in a base fluid of aqueous methanol. The discussion will include chemistry, rheological evaluations, and successful field utilization of these fluids in the Western Canadian Sedimentary Basin over the last decade.
Integrated Fracture Analysis– Three Brief Case Studies
Authors: Ozkaya S. I. 
Published: December 2007

Abstract
Three short case studies are presented to demonstrate the power of data integration in fracture evaluation and to sample the wide spectrum of challenges each field may present. The three short case studies reveal the kind of problems that may arise specific to each field and reservoir. In the first case, an unexpected observation that the mega-fractures are associated with a sharp Gamma ray anomaly allowed field scale mapping of the mega-fractures using gamma ray logs from horizontal wells. In the second case, identification and correlation of highly fractured layers and water invaded zones made it possible to determine whether fractured layers acted as thief zones. In the third case, the challenge was to find a means of separating fluid conductive and sealing fractures and faults in a clastic reservoir and generate a water breakthrough risk map. In each of the three cases, a solution or partial solution to the fracture problems was possible only by integrating all the available seismic and dynamic data with borehole image and openhole logs.
Wellbore instability of Shale Formation; Zuluf field, Saudi Arabia
Authors: Abass H. , Shebatalhamd A. , Khan M. , Al-Shobaili Y. , Ansari A. , Ali S. , Mehta S. 
Published: December 2007

Abstract
Significant wellbore instability problems are being experienced during the drilling of horizontal wells in a shaly sand member of the Khafji reservoir in Zuluf field. This paper presents the results from a case study that integrates detailed rock mechanics and swelling tests with information from petrophysical logs and core properties acquired to evaluate, define and predict the instability mechanism in this portion of the Khafji reservoir.
The study has tackled the effect of drilling fluid on shale strength and swelling. Additionally the effects of water activity, osmosis and hydraulic diffusion on shale stability were investigated. The mechanical properties and stress field in the khafji shale was determined. The results provided recommendations to minimize instability problems encountered during drilling. All drilling fluids that have water phase including the oil-based drilling fluid were found to cause instability problems. However all-oil drilling fluid was found to maintain shale strength. Drilling mud salinity to encourage resverse osmosis was determined based on measurement of shale-pore-water salinity. The critical mud weight window was calculated considering the Chemoporoelastic properties of the Khafji shale.
Analytical Calculation Of Minimum Miscibility Pressure By Using Stability Analysis In Reduced Variable Space
Authors: Shahri Mohammad R. Rahmanian , Edalat Mohsen 
Published: December 2007

Abstract
Miscible gas injection is one of the most efficient methods in enhanced oil recovery and Minimum Miscible Pressure (MMP) is a vital parameter in miscible injection projects. In this paper a new method of MMP calculation is presented which is based on stability analysis in reduced space variables and consists of a fast and robust algorithm which guarantees that increasing the number of components of oil and injection gas has no effect on the volume of calculations; nevertheless the accuracy of calculation does not change. It is illustrated that using stability analysis in reduced space for miscibility development and consequently in MMP calculation causes that the number of equations for "C" components to reduced marvelously to "m" equations (m is less than or equal to 6). Thus in addition of accuracy and fastness this method offers that there is no need for splitting, lumping or pseudo component definition. Comparisons in examined cases demonstrate that this claim is correct. By this method of MMP calculation, the hardships in phase calculation due to existence of the ragged shape of Gibbs free energy function and consequently the existence of several minimum points and difficulty in finding a proper solution for nonlinear Ratchford-Rice equations especially near the critical point and also complication in analytical tie line intersection approach for MMP calculation are obviated. The analytical algorithms for calculating MMP for general multi component systems are tested against slim tube test data for real crude oil systems. It is shown that for all the crude oil systems considered, the displacement is a condensing/vaporizing gas drive. The MMP calculation results indicate that the analytical stability analysis approach can be used to calculate MMP accurately for systems with an arbitrary number of components, provided that an appropriate equation-of-state based on phase behavior characterization is available. This approach is significantly faster than the conventional compositional simulation approach. It is applicable to all systems with any type of displacement mechanism, and hence it can be used in areas that call for rapid calculation of MMP.
Eliminating Disposal of Effluent Water to Pits and Utilizing the Water To Recharge an Ever-Falling Reservoir Pressure
Authors: Quttainah Riyad , Al-Khamees Waleed , Al-Qabandi Salman Ahmad 
Published: December 2007

Abstract
Since the discoveries of West Kuwait (WK) oil fields, and for 40 years before commissioning the Minagish water injection plant (MNWIP), all effluent water from WK fields was disposed off into huge evaporation pits. And, as a result of a thin layer of oil forming on the top, the rate of evaporation was reduced and in some cases completely eliminated which left large amounts of effluent water in those pits. This practice subjected all animal life to be affected and threatened. Moreover, the seepage of water into the ground and mixing with spring water caused multiple concerns. Polluting the water and hence making it hazardous for usage and consumption. Therefore, it was considered to be a health and an environmental hazard to continue with this practice.
Water management in WK was designed to integrate all effluent water from gathering centers in WK through the Effluent Water Transfer System (EWTS) and the MNWIP. All effluent water is transferred from the gathering centers through the EWTS to the MNWIP for re-injection into the Minagish Oolite (MO) reservoir in the Minagish field (MN) for pressure maintenance. The reinjection of all effluent water produced from WK fields into the MO reservoir has significantly increased reservoir pressure. This operation increases the well potential (oil production) and helps insure that oil production is available to fill the gathering centers to meet oil export demands. Also, disposal wells were drilled to inject off spec or surplus water into the Shuaiba reservoir as a back-up plan in case of any planned or unplanned shutdown of the MNWIP.
Since mid-2003, all effluent water in WK has been routinely disposed of in an environmentally friendly manner with no discharges to pits and in return, increased reservoir pressure which will have huge economical benefits.
Technical Contributions: The environmental impact from disposing off into large disposal and evaporation pitsThe total production from all WK fields and the unique and complex network of transfer lines between all centers to gather effluent water and disposal design.The economic impact from injecting effluent water to re-pressurize a constantly depleting reservoir.
Oilfield Surfactants Improve Recovery by Imbibition
Authors: Weiss W. W. , Xie X. 
Published: December 2007

Abstract
Most carbonate reservoirs are naturally fractured and typically produce less than 10% OOIP during primary recovery. Spontaneous imbibition is an important oil recovery mechanism from these types of reservoirs. In some situations, imbibition of water can be promoted by chemical stimulation with surfactants to alter the reservoir wettability toward water-wetness such that oil is expelled at an economic rate from the rock matrix into fractures. Here, we investigated the use of chemicals to modify the wettability of reservoir rock to a more water-wet state in order to produce additional oil via imbibition. Five chemicals that effectively improved water-wetness were used in the imbibition tests: two nonionic surfactants Tomadol T91-8 and Pluronic L-64, two anionic surfactants Rhodacal A-246L and Rhodapex CD 128, and an amphoteric surfactant Mirataine CB.
The San Andres formation in the Permian Basin of Texas and New Mexico is a great oil-producing formation in the United States. An estimated 50,000 wells produce oil from this oil-wet carbonate reservoir. Laboratory imbibition tests were conducted on core plugs and fluids from the Fuhrman Masho and Eagle Creek fields. Thin section analysis indicated that both fields contain dolomite, calcite, and anhydrite. The core plugs were soaked in imbibition cells containing formation water at a reservoir temperature of 40°C (104°F). For Fuhrman Masho cores, maximum oil recovery via water alone was less than 4% of the original oil in place (OOIP). After the oil production stopped, the water was replaced with a surfactant solution at a concentration of 1500 to 3500 ppm. The imbibition process then continued until no oil was produced. The incremental oil recovered varied from 0 to 48% OOIP; higher permeability and bulk volume of oil in the cores resulted in higher oil recovery by surfactant imbibition. No oil was produced by brine imbibition for some Eagle Creek cores; however, others produced up to 34% of the OOIP. Surfactant treatment did not improve oil recovery every core. The laboratory tests indicated that the improved oil recovery by surfactant treatment depended on rock mineralogy, porosity, permeability, and pore heterogeneity. Each field must be individually evaluated.
Recent HP/HT Coiled-Tubing Intervention and Perforating Operations on the Jade Field
Authors: Turner Alan , Gordon William , Nicol Iain , Cromar Steve 
Published: December 2007

Abstract
This paper describes the results obtained, as well as the equipment and techniques used on the Jade Field in the UK Central North Sea to provide the perforation and completion operations of two new high-pressure/high-temperature (HP/HT) production wells.
This paper begins by discussing the types of equipment that are required for HP/HT coiled-tubing (CT) intervention. The completion design and methodology of these two wells will be discussed. The CT interventions and different perforating operations will then be presented for these wells. The paper outlines the specific types of downhole equipment that were needed for these operations. This includes, for example perforating gun hangers and detachable perforating connectors. This paper includes the application of new equipment designs and novel solutions to both surface and downhole constraints.
Lessons learned from each case history will be presented and conclusions will be drawn.
The Possibility of Replacing Oil-Based Mud With the Environmentally Acceptable Water-Based Glycol Drilling Mud for the Iranian Fields
Authors: Samaei Seyed Mohsen , Tahmasbi Koorosh 
Published: December 2007

Abstract
Oil-based mud has been used in the last few decades in the drilling operation in the world. Due to high initial cost and environmental problems associated with oil-based mud, the application of this type of drilling fluids has been gradually reducing. This has therefore dictated the companies and institutions dealing with drilling fluids technology to work on finding a suitable substitution to replace oil based mud.
A proper alternative has been known to be Water-based glycol mud. Water-based glycol mud is becoming increasingly popular due to its exceptional shale inhibition properties, environmental effectiveness, and ease of handling and high lubricity.
In This study, the possibility of replacing oil-based mud with the environmentally acceptable water-based glycol drilling mud for the Iranian fields is investigated. Rheology test is done on both OBM and glycol mud. In addition, the inhibitive property of the glycol mud is assessed using Shale particle disintegration test by hot rolling. This test is done on the cuttings from Maroon oil field and outcrop shale from Goorpi formation in Iran and shale recovery percentage is measured to evaluate the inhibition performance of glycol mud. The laboratory results confirm that the glycol mud system significantly reduces clay dispersion and hydration of cuttings and can be considered as a good alternative to oil-based fluid and other water-based mud systems.
The Integration of HSE&C—Communities, Contractors, Operators, and Regulators
Authors: Doyle Rex , LeBlanc Tad 
Published: December 2007

Abstract
Continuous improvement in safety and environmental performance is a goal for most all companies in the energy industry. But substantially improving performance, that is creating a step change in the metrics used to measure performance in the field, requires an expanded view of Health, Safety, Environment, and Compliance (HSE&C) programs. These programs must be viewed as both an integral part of each company's organization and more importantly as programs that are continually integrated into an expanded network of organizations – operators, contractors, suppliers, communities, and regulators. Companies must proactively move from successful stand alone programs to programs that easily and effectively interact with all participants and participating organizations.
Two factors that are highly correlated with improved performance in this network environment are workforce competency assessment and communication. Competency assessment is critical in that employees must be placed in the right job and have the knowledge required to successfully and safely execute the skills required of the job. Effective two-way communication between all organizations in the network is vital in creating an environment where information and expectations are shared among participants. It is especially important to engage the regulatory authorities, both internal departments and governmental agencies, in the process.
Integrating HSE&C into a network of organizations does not necessarily require a complete redesign of existing programs, rather it requires a new approach that actively looks for ways to work with each of the other participants to improve the performance of the group.