bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Review on Utilization of Crosslinked Polymer Gels for Improving Heavy Oil Recovery in Turkey
Authors: Topguder Nazan N. 
Published: July 2010

Abstract
The oil reservoirs in Turkey generally produce from naturally fractured carbonates with high WOR's. This high WOR easily causes rapid decline in oil rates, especially with heavy oil of about 18-20° API. As crosslinked polymer gels are one of the major means to remedy this problem, gels for WOR reduction in oil producers have been applied in TPAO oilfields. Treatments have provided several folds of increase in net oil (from 30 b/d to 120 b/d) production and reduction in WOR from 96-98 % to 30-75%.
Another application of crosslinked polymer gels is conformance control in IOR processes, e.g. CO2 injection, where mobility reduction and improved sweep efficiency is required. Polymer gels provide mobility control by decreasing the permeability of the porous medium, hence CO2 injection pressure is increased and also it is diverted to the previously bypassed zones to recover more incremental oil.
This process is extremely important if the displaced oil is heavy; where that is the case in Bati Raman CO2 injection project of TPAO, which is a well known field project that has been going on for more than twenty years. Crosslinked polymer gels for conformance control have been employed recently in Bati Raman field providing improved sweep efficiency and 12 % increase in net oil recovery.
Field application of polymer gels for water shutoff and conformance improvement have provided both technically and economically successful results in naturally fractured carbonate heavy oil reservoirs in Turkey. The design and field operation process and experience gained from these applications may be very helpful and encouraging for the operators who look for new, reliable and low-cost methods to improve their oil production under today's harsh economic conditions.
Scale Inhibitor Squeeze Treatment Efficiency in Unfractured and Fractured Wells
Authors: Ishkov Oleg , Mackay Eric , Sorbie Ken 
Published: July 2010

Abstract
Deployment of scale inhibitor squeeze treatments generally involves injection of aqueous solutions at pressures higher than the formation pressure and at temperatures lower than the formation temperature. If the pressure and temperature differences are great enough, the pumping activity may lead to the development of fractures in the near-well bore area, if the well has not already been fractured and propped. Therefore, attention needs to be paid to the impact of squeezing fractured wells, unfractured wells, or wells that fracture during the scale inhibitor squeeze treatment.
This paper presents results of using a simulator to model squeeze treatments for these three scenarios. The simulator has the unique combination of being able to model (i) scale inhibitor propagation and retention in the porous medium, (ii) scale squeeze treatments in unfractured or fractured wells, (iii) the mechanics of fracture propagation during a treatment, (iv) the geochemical reactions that may lead to in situ dissolution or precipitation, and (v) the impact of the injected scale inhibitor on these reactions when they occur within the treatment zone.
Parameters considered in this study include locations in the matrix where scaling reactions occur, and fracture geometry and conductivity. If a fracture is created, the timing of this relative to the injection of the main scale inhibitor treatment volume has also been studied and is found to be very important.
Inappropriate placement of scale inhibitor during a squeeze treatment may mean that downhole zones at risk of scale damage are not adequately protected, even although the observed inhibitor concentrations at the wellhead are above the level required for protection. In this work, a new approach is presented also in which we define and measure the "efficiency" of the squeeze treatment based on produced water ion compositions. This approach takes account of whether the scaling reactions would take place in the treated zone (and hence should be impacted by the presence of inhibitor), or whether they would take place deep within the reservoir.
Effect of Gas Type on Foam Film Permeability and Its Implications for Foam Flow in Porous Media
Authors: Farajzadeh R. , Muruganathan R. M. , Krastev R. , Rossen W. R. 
Published: July 2010

Abstract
The ability of foam to control the gas mobility in porous media is determined in part by the trapped (stationary) fraction of foam, Xt. The common approach to determining Xt is to replace some part of the gas by a "tracer gas" during the steady-state stage of the experiments and fitting the effluent data to a capacitance mass-transfer model. Diffusion between bubbles is quantified by the film permeability coefficient, K (cm/s). We measured the film permeability coefficient of different gases for foam films made of four surfactants. The results show that the value of K is largely dependent on the dissolution of gas in the surfactant solution and increases with increasing gas solubility in the bulk liquid. The measured values of K are consistent with rapid diffusion of tracer through trapped gas adjacent to flowing gas in porous media, and difficulties in interpreting the results of tracer-foam experiments with conventional capacitance models. Effective diffusion coefficients of gases through trapped foam can be estimated from K. These diffusion coefficients differ substantially, and this implies swelling or shrinkage of trapped gas from diffusion. The implications of the results for foam flow in porous media is discussed in detail and some suggestions are given to improve the measurements and modeling of trapped fraction of foam.
Improved Oil Recovery in Chalk: Wettability Alteration or Something Else?
Authors: Zahid Adeel , Stenby Erling H. , Shapiro Alexander A. 
Published: July 2010

Abstract
Improved oil recovery from low permeable chalk reservoirs is regarded as a great challenge because of their complexity and heterogeneity. Historically seawater salinity has not been considered as an important factor in determining the amount of oil recovered. Over the last decade, a number of studies have shown that waterflooding performance is dependent on the composition of injecting brine solution. Extensive laboratory research has been carried out in order to understand improved oil recovery from chalk using surfactant solutions and later on using the modified sea water. The researchers suggested wettability alteration towards more water wetting conditions to be the reason for improvement in oil recovery.
In this paper, we are further investigating the reasons of observed improvement in oil recovery with sulphate ions. Is it really wettability alteration or something else also? Most of the previous work has been made on the basis of spontaneous imbibition using core plugs aged in crude oil. Our study is based on flooding and utilizes completely water wet cores without being aged in crude oil, just saturated with crude oil under vacuum. This would exclude alteration of wettability as a positive factor. Brine without sulphate is considered as the base injected fluid. Waterflooding experiments were carried out with brines without sulphate, as well as brines having different concentrations of sulphate. The effect of temperature, injection rate, crude oils and different sulphate concentration on the total oil recovery and the recovery rate was investigated.
In Stevens Klint outcrop chalk samples, 10% increase in oil recovery was observed with sulphate enriched brine flooded core as compared to core flooded with brine without sulphate ions. We observed also 4-6 % increment of OOIP using brine with sulphate for water wet chalk at high temperatures. This clearly indicates improvement in oil recovery without wettability alteration, because chalk is already water wet. No increment in oil recovery was observed at 40 ºC and, neither, in experiments with North Sea crude oil. This clearly explained that crude oil type also plays a significant role in the effect that brine composition has on waterflood oil recovery.
This study will help in getting more in depth understanding of seawater improved oil recovery process for chalk reservoirs.
Comprehensive Pre-Well Preparation and Collaboration Leads to Record Drilling Performance in Challenging Exploration Well in Sichuan
Authors: Lee Roger , Chang George , Bo Li , Wei Zhang , Jin Xu , Qing Zhu Cheng , Xiang Xia Jia 
Published: July 2010

Abstract
China's Sichuan Province contains prolific gas fields and offers many drilling challenges due to the complex structural geolo gy. The interbedded and abrasive nature of the lithology results in slow drilling penetration rates. Additionally, risk of cavings and stuck pipe limits use of fully stabilized BHAs.
Conventional roller cone and PDC bit technologies had been tested and were limited by impact damage and abrasive wear. Offset wells required more than 230 days due to short drilling intervals and subsequent tripping time. The goal set by the operator was to complete drilling a well in the XinChang Gas Field in less than 180 days. The target well would reach 4700 m total vertical depth (TVD) and contain a challenging 2500-m long 9 1/2-in. interval. Improving rates of penetration (ROP) and increasing distance drilled would be essential in this section.
To identify the solution, a cross-functional team from the operator and the service company conducted extensive technical reviews. Proprietary software was used to analyze the rock properties, and formation drillability problems were identified. BHA modeling revealed potential system instability issues and provided methods to mitigate vibrations. Review of offset drill bits provided clues to drilling challenges and helped form realistic drilling expectations. The correct solution incorporated both products and service. A revolutionary PDC drill bit containing wear-resistant cutters and an innovative design replaced multiple bits and extended the interval drilled by over 80% in certain sections. More importantly, drilling ROP increased by 60%. Experienced bit run supervisors monitored the drilling process and provided real-time options for improving performance.
This paper will describe the application analysis and review process, the critical PDC bit technology, and the implementation instrumental in achieving the 180-day drilling completion goal set by the operator.
Fracture Modeling and Application Based on Fracture Mechanics
Authors: Mingming Tang , Jinliang Zhang , Xiaoyu Yu 
Published: July 2010

Abstract
Based on the analysis of fracture classification, controlling factors and distribution characteristic, in this article we established the fracture intelligent recognition system. In the reservoir fracture forecast modeling aspect, we established one one FM2 (fracture modeling based on fracture mechanics) system by combining geological statistics and fracture mechanics. Based on the modern fracture mechanics, has established FM2 system. The model has not only considered the temperature field and strain field coupling effect, and introduces Green Strain tensor in the small distortion analysis. Because of the reservoir existence varying degree's aeolotropies, so in the elastoplasticity stress and strain field simulation, mainly uses kinematics hardening theory. But the fracture distribution also influenced by later period structure change and others kinds of factors. In order to compensate the influence of these factors to facture distribution, the auto-adapted intelligent field control fracture modeling method is first raised in this article. Based on the common field control fracture modeling method, by contrasting the fracture distribution data obtained from micro electrical receptivity well log, modify the boundary condition and modulus by according to the error to make the simulation results achieve the most superior match.
The Inhibition of Gas Hydrates and Synergy of the Inhibiting Molecules
Authors: Guan Hua 
Published: July 2010

Abstract
Gas hydrates have become an increasing problem to the oil and gas industry as the development entering deeper water encounters high-pressure and low-temperature regions. However, the mechanisms and applications of kinetic hydrate inhibitors are less well understood. This paper provides an overview of the performance of common hydrate inhibiting molecules that are currently available and discusses the mechanisms of hydrate inhibition and the synergy of different hydrate inhibiting molecules and therefore provides some guidance in future development on hydrate inhibiting molecules for different gases.
This paper investigates the application of kinetic hydrate inhibitors in three different gases and the synergy between different inhibiting molecules. Several commercially available kinetic hydrate inhibitors have been evaluated in the laboratory using a rocking cell apparatus. Three different gas compositions were used in the performance evaluation. The synergy of different inhibitor molecules has been studied through the evaluation of various mixtures. The field requirement for low viscosity and high cloud point for kinetic hydrate inhibitors have also been studied and discussed. The hydrate dissociation curves for three gases have been modelled and the subcooling potential for each of the products has been calculated.
Following the review and optimisation of the different hydrate inhibiting molecules available in the market, it was found that one of the optimised mixtures has outperformed all the individual hydrate inhibiting molecules and mixtures for all three gases. This suggests synergy between the different hydrate inhibiting molecules; the possible mechanisms are discussed in this paper.
Calibration and Analysis of a Novel Downhole Sensor to Determine Fluid Viscosities
Authors: Rondon Javier , Barrufet Maria A. , Falcone Gioia 
Published: July 2010

Abstract
This paper presents the performance evaluation of a novel sensor designed to measure the in situ the viscosity of a flowing fluid at downhole conditions. The device provides a mechanism to allow the passage of solid particles (i.e. sand) and has a self-cleaning ability should any build-up of these particles restrict the flowing area. The sensor was assembled in a closed flow loop to prevent measurement error due to partial vaporization of the samples at higher temperatures where it was tested and calibrated with mixtures of glycerin and water. Differential pressures, flow rates and temperatures were gathered and used to determine the viscosity of two crude oils with viscosities ranging from 1 to 30 cp and temperatures from 100 to 160 °F. Flow rates were controlled to maintain linearity in the differential pressure response to ensure a laminar flow regime. Viscosity measurements were validated with independent measurements using a Brookfield viscometer and the agreement was within 2%. Using data from this sensor, new viscosity mixing rules were developed to allow determination of mixture compositions from viscosity measurements or mixture viscosities for given compositions. Potential applications include the estimation of diluent to be added to a more viscous fluid to achieve a target viscosity reduction, fluid identification from wireline formation testers, smart well fluid monitoring, enhanced mud logging, and fracture fluid characterization.
Practices of Formation Damage Control for Deep Fractured Tight Gas Reservoir in Western Sichuan Basin
Authors: Yili Kang , Lijun You , Xinghua Xu , Zhonghui Liao 
Published: July 2010

Abstract
Western Sichuan deep tight gas reservoir is characteristic of ultra low permeability, natural fractures developed in heterogeneity, partial ultra low water saturation, hard and brittle shale interlayer. The matrix permeability varies between 0.001mD and 0.1 mD, and the natural fracture width is between 10μm and 2.0mm, while the fracture width can reach up to 5.0mm during the well operations. Lost circulation, inducing severe reservoir damage and increasing non-productive time, happens more frequent. The traditional lost circulation control technologies such as physical, chemical or physicochemical methods, used to permanently chock the lost circulation passage of non pay zone, is not applicable to pay zone. One after another technology such as air underbalanced drilling fluids, non-invasive drill-in fluids and the traditional temporary shielding fluids technology(TSF) were executed for prevention of formation damage duo to lost circulation, but they all do not work well. The air underbalanced drilling has to be given up because of formation water influx and wellbore instability, and non-invasive drill-in fluids does not obtain good results duo to low return permeability rate and low loading pressure ability of filtrate cake in the fractured formation. The traditional temporary shielding fluids technology (TSF) is not competent for the damage prevention of the reservoir with ultra narrow pores and throats. In the light of the special geology and engineering characteristics, a named temporary sealing loss (TSL) fluids with inert particles and acid soluble particles are developed to prevent formation damage in leaky fractured reservoirs. Integrating the advantages of non-invasive fluids and temporary shielding fluids, temporary sealing loss (TSL) technology takes advantage of inert bridging particles and acid soluble filling particles to rapidly form tight plugging zone near the wellbore to seal the throats and fractures effectively. After its application, well X2 and X3 obtain gas production of 52.16×104m3/d and 22.37×104m3/d in 2nd member of Xujiahe formation, respectively.
Innovative Cementing Solution for Long-Term Steam Injection Well Integrity
Authors: DeBruijn G. , Loiseau A. , Chougnet-Sirapian A. , Piot B. , Pershikova E. , Khater W. , Evoy K. , Wilson G. 
Published: July 2010

Abstract
Operators involved in the recovery of hydrocarbons from heavy-oil reservoirs often face the problem of maintaining well integrity in steam-injection wells. A significant portion of these wells suffer various forms of leaks and in the most severe case complete steam breakthrough to surface. Throughout the life of heavy-oil wells, cement material degradation and stresses in the cement sheath induced by extreme temperature cycling result in severe mechanical damage and ultimate failure of the cement sheath. These problems motivate different operators to explore new cementing technologies that are capable of achieving reliable long-term zonal isolation in these extreme conditions.
The main challenge for operators is to design thermally stable cement with mechanical properties sufficient to withstand stresses induced by the large temperature changes. This paper describes the development of a new cement system, which is stable, strong, impermeable and flexible up to a temperature of at least 350°C(650°F), corresponding to the maximum steam injection temperature. Depending on the curing temperature this new cement system provides low Young's modulus of 1,800 to 4,000 MPa while maintaining excellent compressive and tensile strengths compared to cements currently used in the oilfield industry. Aging the cement system for 6 months at steam temperatures demonstrates the stability of the set material properties, including maintaining a low permeability.
Field trials in North America show that this new cement system can be easily implemented into standard cementing operations using conventional equipment. Cement evaluation logs after cement operations confirm that excellent zonal isolation and wellbore integrity are readily achieved.
By keeping adequate strength and flexibility, this new cement system reduces the risk of cement sheath failure and steam migration throughout the life of these steam-injection wells. It provides a long-term well integrity solution for any well exposed to very large temperature increase after the cement initial set, such as in fields exposed to steam temperatures.
Use of Modified Hollow Cylinder Test in Laboratory for Simulation of Downhole Drilling Condition in Shale
Authors: Gabrielsen Glenn K. , Stenebråten Jørn F. , Nes Olav-Magnar , Holt Rune M. , Horsrud Per 
Published: July 2010

Abstract
Several challenges are experienced with wellbores when drilling in shale above and within reservoirs. These are especially prevalent in deviated wells and wells through depleted intervals caused by some years of production.
Drilling the well to total depth of the wellbore section might be easy. However, in some cases depending upon formation properties and drilling conditions it is a big challenge to come out of the hole and subsequently run casing or liner. It is of great importance to take the right actions regarding recommended downhole parameters like mud circulation rate, RPM on drillstring and pulling speed.
Some of the wellbore aspects to discuss are: unstable hole, small margins between mudweight and collapse pressure, what is the right technique to use with the drillstring, flow rates and finally oil based mud versus water based mud. In case of a marginal downhole situation, it would be beneficial to test out some effects in a laboratory beforehand.
Such questions were discussed and became an issue within a joint industry project on borehole stability in shales run at SINTEF Petroleum Research (SPR). A modified test cell was designed and used with the purpose of systematically testing these effects in the laboratory.
This paper describes how this equipment was designed and tested in order to achieve reliable laboratory results as well as results from initial work on outcrop shale. The main objective was to a certain extent to visualize some effects in a laboratory and conclude with some good recommendations regarding drilling procedures on the rig offshore. Thus for testing some of the down hole effects, a long period of qualification tests was gone through. This was important before real tests could be done on shale at simulated downhole condition. Testing was performed on hollow cylinder samples.
The initial results show that it is possible to run such laboratory simulations. It is possible to a certain extent to visualize some of the effects with varying flowrates and RPM on a drillstring with stabilizer. The laboratory tests so far suggest that high RPM on a drillstring can have destabilizing effects on a wellbore through a section with shale that has been exposed to very close to collapse conditions, calling for optimized drilling procedures in situ.
Rotary Steerable System Enhances Drilling Performance on Horizontal Shale Wells
Authors: Sugiura Junichi , Jones Steve 
Published: July 2010

Abstract
In North America, shale gas wells are typically drilled with build rates of 10°–14°/100ft to land, followed by 3000–5000 ft horizontal sections. As more shale plays open up, horizontal sections have been extended to seek more shale exposure. Today, the majority of shale gas wells are drilled using conventional steerable motors, but as horizontal sections get longer, Rotary Steerable Systems (RSS) become a more viable option to reach the target depth.
Standard RSS currently on the market cannot provide sufficient build rates to drill the curve on shale gas well designs. However, as wells step out further, it has become more common to drill the curve with steerable motors and to drill the lateral with RSS. On shale wells where the curve and the lateral are drilled in the same hole size, it would be more efficient to drill the entire well with RSS. Hence, there is a necessity for higher-dogleg RSS for these applications.
This paper describes the development and testing phase of a new 6 ¾-in. RSS that can produce higher build rates than the standard RSS on the market. During testing, the 6 ¾-in. RSS proved to be capable of producing 12°–15°/100 ft in 8 ½-in.- and 8 ¾-in.-hole-size sections. The system was tested under controlled conditions through variable rock strengths to ensure consistent and predictable build rates, as well as fine dogleg control for horizontal sections.
When sufficient test data had been gathered to prove the RSS was fit for purpose, it was then released for initial field testing on shale gas wells in North America.