bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Polymer Fluid for Hydraulic Fracturing in Russia
Authors: Fu D-K.. , Fedorov A.. , Prudnikov A.. , Mauth K.. , Lungwitz Bernhard 
Published: July 2010

Abstract
Borate-based fluids have been widely used as fracturing fluids for hydraulic fracturing treatments for several decades. Although the fluid system had been studied extensively and the importance of shear recovery was fairlywell understood, the rate of shear recovery for different pumping conditions was still an issue in question. It was commonly believed that fluids crosslinked with borate had reversible shear recovery after exposure to pumping through tubing and perforations. As a consequence, fluids with inadequate shear recovery have been used, resulting in premature screenouts and unnecessary high polymer loadings. We will show that the shear recovery rate is influenced by several physical and chemical factors, such as temperature and pH. Based on the understanding, we have developed a novel fracturing fluid with much-improved shear recovery and simplified operational requirements.
We present the laboratory development of the novel fracturing fluid based on guar and a novel borate crosslinker. The crosslinker is a solid borate material, which allows controllable crosslinking through slow dissolution and instant shear recovery. We used a simple experimental method to study shear recovery behavior in the laboratory and field environment. The new fluid shows excellent compatibility with water sources used for fracturing treatments in western Siberia. The use of dry crosslinker also results in the reduction of polymer loading from 4.2 kg/m3 to 3.0 kg/m3leading to higher proppant pack conductivity. We also describe the field cases of the new fracturing fluid.
The new fluid has significant advantages over the existing technology because of better shear recovery, lower polymer loading, and operational simplicity. It is well suited for operational, logistical, and reservoir conditions in Russia.
A Study of Diversion Using Polymer-Based In-Situ Gelled Acids Systems
Authors: Gomaa A. M. , Mahmoud M. A. , Nasr-El-Din H. A. 
Published: July 2010

Abstract
In-situ gelled acids that are based on polymers have been used in the field for several years, and were the subject of many lab studies. These acids used in stages to block the treated zone and forcing the next regular acid stages to the untreated zones. An extensive literature survey reveals that there are conflicting opinions about using these acids. On one hand, these acids were used in the field, with mixed results. On the other hand, recent lab work indicated that these acids can cause damage under certain conditions.
The ability of polymer-based in-situ gelled acids to divert regular acids was studied using parallel core flood setup. The sequence of the injection involved In-situ gelled acid at 5 wt% HCl stage followed by regular acid at 15 wt% HCl until acid breakthrough. Experimental results show that even for nearly the same permeability formation (1:1.1), regular acid preferred to flow only through the high permeability zones. Therefore, diversion was needed for all acid treatments. At an injection rate of 1 cm3/min, in-situ gelled acid plugged the two cores. For low permeability contrast (1:2), polymer was able to divert the acid with permeability enhancement in both cores.
For high permeability contrast (1: 20 up to 25), in-situ gelled acid was able to divert the acid only at injection rate less than 10 cm3/min. However, at higher injection rates, in-situ gelled acid was not able to build enough pressure that could force the regular acid into the low permeability core. Increasing the injection rate reduced the viscosity of the in-situ gelled acid. Therefore, acid injection rate should be determined based on the expected fluid viscosity in the formation. The results obtained can be used to better design acid treatments in carbonate reservoirs.
An Experimental Study of Alkaline Surfactant Flooding in Ultra Shallow Heavy Oil Reservoirs
Authors: Hunky Rabia Mohamed , Wu Yongfu , Bai Baojun , Dunn-Norman Shari 
Published: July 2010

Abstract
Economic recovery of heavy oil from ultra shallow oil reservoirs (&lt;500 ft) is of interest as many such reservoirs exist throughout Utah, Missouri, and California. EOR methods, such as thermal flooding, can be limited in these ultra shallow situations, and other methods of heavy oil recovery are of interest. A study of alkaline-surfactant flooding for the Pennsylvanian Warner sand in Western Missouri has been conducted. This work has included testing more than 30 commercial surfactants and using sands saturated with heavy oil (API 17). It has been found that a few of surfactants can create a stable emulsion with the Warner heavy oil and the formation brine. In all cases examined, highest recovery is from water wet sands. Chemical flooding tests have found that using these surfactants is better than using other conventional ones. This study benefits the industry by demonstrating the applicability of alkaline surfactant flooding to the Warner sands of Western Missour. This paper presents the detail experimental methods necessary to extrapolate this work to other ultra shallow heavy oil reservoirs. In our experienments, viscosity of Missouri heavy oil can be reduced from 18518 cp to 2.5 cp at 25 °C through emulsion of certain surfactants. Emulsion of the heavy oil and formation brine is stable for several weeks at 25 °C. But heavy oil in the emulsion can be easily separated without addition of deemulsion agent. Alkaline-surfactant (AS) system can change wettability of oily sand from strongly oil-wet to water-wet. Heavy oil recovery by AS flooding test at 25 °C has been improved significantly. Considering the total volume of heavy oil in the United States is 100~180 billion barrels and a significant amount of these reserves are in ultra shallow reservoirs (&lt;500ft). Results of our work demonstrate that alkaline surfactant flooding can be effective on enhancing oil recovery in the ultra shallow heavy oil reservoirs.
Gel Damage Remediation by Evaporative Mechanisms: A Laboratory Investigation
Authors: Le Duc , Mahadevan Jagannathan , McQueen Ken 
Published: July 2010

Abstract
Polymeric gels are widely used in hydraulic fracturing operations to produce natural gas from tight sands. The recovery of injected gel is often poor and large quantities are left behind, which can cause a loss in gas productivity due to a reduction in the fracture conductivity. In this paper, we present a novel study of remediation of gel damage from proppant packs by dry gas injection. We experimentally investigated removal of polymeric fracturing fluid gels from proppant packs and recovery of gas flowrate at constant pressure drawdown conditions.
The gel removal process takes place in two steps, the first being a viscous displacement process which is followed by an evaporation process. Due to the high viscosity, gel removal by simple displacement is ineffective and only 20-30% of the gel is removed at high drawdown pressures and only 3-5 % of the undamaged flowrate is recovered. However, when dry gas is injected, the entire water content in the gel is removed due to evaporation. Results from experiments conducted with sandpacks and fracture-packs show that about 40% of the undamaged flowrate is recovered by dry gas injection. Additional treatment of the trapped gels with alcohol solvent shows that gas flowrate recovery is greater and achieved faster if the dry gas treatment is preceded by a single alcohol soak treatment. The alcohol treatment improves recovery of gas rate due to greater volatility which enhances the evaporation rates.
Dry gas injection is effective in removing water content of the gel from sandpack and fracture-pack. Hence the residual gel saturation is lowered, leading to greater gas relative permeability and gas flowrate. A mathematical model based on drying front propagation is developed to predict the rate of water removal and the recovery of gas rate in damaged laboratory scale fracture and sandpacks. The model prediction agrees well with experimentally observed gas flowrate recovery in gel damaged cores.
Effect of Gravity, Flow Rate, and Small Scale Heterogeneity on Multiphase Flow of CO2 and Brine
Authors: Kuo Chia-Wei , Perrin Jean-Christophe , Benson Sally M. 
Published: July 2010

Abstract
A series of steady state multiphase flow experiments at a range of fractional flows and flow rates have been conducted using Berea Sandstone. Using the multiphase flow simulator TOUGH2 MP with ECO2N module, carbon dioxide saturation distributions, average saturations, and pressure gradients across the core were calculated to determine the influences of sub-core scale heterogeneity, gravity and flow rate on brine displacement efficiency. It is found that measured CO2 saturation patterns can be replicated using simulation models that include spatially varying porosity, permeability and capillary pressure curves.
The interplay of viscous, capillary and gravity forces in core flood experiments is also investigated at different Gravity and Capillary numbers representative of those expected for a typical sequestration project (Gravity numbers: 0~1000 while Capillary numbers: 10-6~10-10). These dimensionless numbers span the range of conditions expected in the near-well region to leading of the plume which may be up to 5 km or more from the injection well. Simulations show that the efficiency of brine displacement and saturation distributions during vertical displacement fall into three separate regimes. (1) At high flow rates representative of the near-well region, the brine displacement efficiency is nearly independent of flowrate. (2) When the Capillary number drops below 10-7 and the gravity number is 2, both the heterogeneous and homogenous cores display flow rate dependent saturation distributions, with brine displacement efficiency dropping by about 80%. Most of this effect is caused by the influence of gravity, as the decrease in brine displacement efficiency is only slightly smaller for heterogeneous cores. (3) At very low capillary numbers, the brine displacement efficiency appears to asymptotically approach a constant value which is independent of flowrate. In this regime, heterogeneity leads to a large reduction in brine displacement efficiency, which is independent of gravity.
Reservoir Simulation of Cyclic Steam Injection Including the Effects of Temperature Induced Wettability Alteration
Authors: Hascakir B. , Kovscek A. R. 
Published: July 2010

Abstract
Cyclic steam injection into representative, low-permeability, hydraulically fractured, diatomaceous, heavy-oil formations is investigated using reservoir simulation. Previous laboratory research has shown that diatomite reservoir rocks exhibit temperature-dependent wettability. Water-oil and liquid-gas relative permeability are varied here and a reservoir simulator used to evaluate the effects on oil recovery. Sensitivity studies are carried out for relative permeability curves compiled from literature for diatomaceous reservoirs. The various parameters included in the analysis are relative permeability end points and viscosity variations with increasing temperature, rock and fluid properties (such as thermal conductivity and heat capacity), injected steam temperature, pressure, and quality, bottomhole pressure for injectors and producers. The results indicate that the liquid-gas relative permeability affects process performance most sensitively because gas displacement determines the shape of the heated zone during cyclic steam injection. For the recovery of heavy oil from diatomaceous formations, realistic evolution of the liquid-gas relative permeability at steam temperatures increases the oil recovery in the range of 15 to 60% of the OOIP in comparison to cases with no evolution of wettability with temperature. Very short two week cycles (inject-soak-produce) make more oil and show greater sensitivity to the evolution of wettability with temperature.
Evaluation of CO2 Injectivity from Waterflood Values
Authors: Nagineni Venu , Hughes Richard G. , D'Souza David , Deets Kenneth M. 
Published: July 2010

Abstract
Carbon dioxide flooding is a common IOR method employed in fields which have relatively easy access to CO2. In some cases, estimating the CO2 injection rate is the most important design parameter which decides the planning, field implementation and eventual success of a flood. This paper presents a method for evaluating this important parameter from data that should be readily available for a field.
Water injectivity index values from fields which have undergone waterflood operations are compared to injectivity index values for the same field while undergoing CO2 flood operations. Different methods for evaluating the indices are presented as is a process for estimating the CO2 injectivity value from data from secondary operations.
The correlation developed has been verified on injectors which were converted in the same field. Initial injection rates calculated from this correlation were in closer agreement to actual injection rates than those predicted by other theoretical formulas.
Intelligent Time Successive Production Modeling
Authors: Khazaeni Y. , Mohaghegh S. D. 
Published: July 2010

AbstractProduction data analysis has extensively been applied to predicting the future production performance and field recovery. These applications are mostly on a single well basis. This paper presents a new approach to production data analysis using Artificial Intelligence (AI) techniques where production history is used to build a field-wide performance prediction models. In this work AI techniques and data driven modeling are utilized to predict future production of both synthetic (for validation purposes) and real field cases.In the approach presented in this article production history is paired with geological information from the field to build datasets containing the spatio-temporal dependencies amongst different wells. These dependencies are addressed by compiling information from Closest Offset Wells (COWs) that includes their geological and reservoir characteristics (spatial data) as well as their production history (temporal data).Once the dataset is assembled, a series of neural networks are trained using backpropagation algorithm. These networks are then fused together to form the "Intelligent Time-Successive Production Modeling"(ITSPM) system. This technique only uses the widely available measured data such as well logs and production history of existing wells to predict a) future performance of the existing wells, b) production performance of the new (infill) wells and c) the initial hydrocarbon in place using a "volumetric-geostatistical" method.To demonstrate the applicability of this method, a synthetic oil reservoir is modeled using a commercial simulator. Production and well-log data are extracted into an all-inclusive dataset. Several neural networks are trained and validated to predict different stages of the production. ITSPM method is utilized to estimate the production profile for nine new wells in the reservoir. Furthermore, ITSPM is also applied to a giant oil field in the Middle East with more than 200 wells and forty years of production history. ITSPM’s production predictions of the four newest wells in this reservoir are compared their actual production.
Experimental and Theoretical Studies of Flocculated Asphaltene Deposition From Oil in Porous Media
Authors: Rezaian A. , Kordestany A. , Jamialahmadi M. , Moghadasi J. , Khoshdaregi M. Yousefi , Alipanah M. , Sefat M. Haghighat 
Published: July 2010

Abstract
Formation damage due to asphaltene deposition in oil reservoir is an issue for many countries that can have strong effect on oil production during heavy oil recovery, miscible flooding, and even primary recovery. Many tests were performed by researchers to determine the amount of deposition and reduction of permeability but the boundaries in which the asphaltene deposited in oil or at the pore surface are not determined.
In this paper, series of tests are performed in order to determine the effect of asphaltene deposition on sandstone rock. Assuming negligible change of viscosity due to various concentrations of asphaltene added, results of laboratory tests performed using pre-separated asphaltene contents from crude oil are showed, to be sure that the first stage (if we divide it into precipitation from liquid phase and deposition on pore surface) of depositing is passed, n-hexane used to flocculate asphaltene particles. To generate reliable data on formation permeability damage due to asphaltene deposition, several dynamic displacement experiments with oil asphaltene content were conducted in various rates and concentrations.
These laboratory tests have shown evidence of core damage happening under dynamic flowing conditions. Data were plotted in order to determine the effect of permeability reduction with comparison to reference oil permeability. It shows a significant permeability reduction after flooding. The results have shown that removal and deposition processes occurred simultaneously and trends were similar to previous works where they follow a straight-line pattern except where removal occurs. The previous available models on CMG roughly matched the data.
The test results and data can be used in formation damage due to asphaltene deposition models for matching and checking models available in literature and commercial softwares.
Joint Development of an Environmentally Acceptable Ester-Based Drilling Fluid
Authors: Amin R. A. , Clapper D. K. , Norfleet J. E. , Otto M. J. , Xiang T. , Hood C. A. , Goodson J. E. , Gerrard D. P. 
Published: July 2010

Abstract
Drilling through highly sensitive shale areas with challenging well profiles, including highly deviated and extended long reach, require the use of an oil-based mud (OBM). However, environmental legislation restricts the discharge of drilling waste/cuttings especially when the cuttings are contaminated with OBM. Therefore, a more environmentally acceptable drilling fluid system is required. The palm oil derivative drilling fluid system is one of the alternatives to meet the challenge.
Joint development was carried out in Kuala Lumpur and Houston with the goal to develop a high-performance synthetic-based drilling fluid. Three esters of interest were evaluated for possible use as the external phase of an invert emulsion. The testing conducted with the esters included elastomer compatibility testing, base oil viscosity, drilling fluid properties and Leptocheirus 10-day bioassays. A series of tests were also conducted with the blend of ester and paraffin and a blend of ester and mineral oil. Fluids were successfully formulated with a minimum number of components including organophilic clay, emulsifier, calcium chloride brine and barite. Several systems were tested for property changes in response to weight up or contamination with simulated drill solids, seawater or cement. Most systems exhibited acceptable changes in fluid properties. Fluids were observed to be stable up to the test aging temperature of 250°F (121°C). Based upon the tests completed, a more environmentally friendly synthetic oil-based drilling fluid has been developed.
Designing of Ultralight Slurry for Liner Cementation: Case Study
Authors: Nabi A. G. , Qureshi S. A. , Arif M. U. 
Published: July 2010

Abstract
Yaqut -1 well is located in Safed Koh Lease of Dewan Petroleum Pvt Ltd. The well was a Re-entry Well. Original well was drilled in 1984 and was classified as dry well.
Dewan Petoleum decided to re-enter the same well and drill down 1356m of 6" hole to test the potential of Chiltan limestone as primary target and Sembar and Lower Goru sands as secondary targets.
The Well is located in tectonically stressed/ active area with fractured formations with under-hydrostatic head. This is the cause of severe losses even at Normal Hydrostatic head. The same case happened also with offset well drilled to same depth. Cementation of liner/ casing was very poor which generated many operational issues in post-completion life of the well.
Keeping this in mind, we worked on different options of slurry design, mechanical barication i.e use of External Casing Packers, Expandable Rubber Sleeves etc and multistage cementation. The geometry of 6" hole of about 1356m long interval and 5" Liner length of 2278m, did allowed only to manipulate with Slurry weights and discarded all other options. The final option of 7.9ppg Slurry was finalized after authentic Lab test results and ensuring slurry properties.
Designed slurry was pumped with only 28bbl loss out of 140bbls. The USIT Log was carried out which showed best cementation results.
This paper will discuss in detail the comparison of cementation results of Yaqoot-1 well with offsets. Detailed discussion of slurry designs considered for subject well along with application in under-hydrostatic fractured formations. Lab results of slurry design and USIT Logs have also been discussed in this paper to conclude the strategical justification Ultra Light Slurry Design.
Waterflood Tomography: Mapping High Contrast Permeability Structures Using Injection/Production Data
Authors: Lin Yenting , Ortega Antonio , Nejad Amir Mohammad , Ershaghi Iraj 
Published: July 2010

Abstract
The paper presents a novel method to detect the existence and determine the orientation of high permeability channels between injection and production wells in a waterflood. We apply the concept of transmission tomography and model a waterflood reservoir by considering water injection rates as inputs and measured production rates as outputs. We solve the inverse problem, in which the goal is to determine the existence and location of high permeability channels in the field by measuring the lag time in response to the variation in the injection rate. The main advantage over other methods (e.g., tracer testing) is that this technique can be applied without significantly affecting daily operation.
We show that the lag times at the producers can be estimated by monitoring production rates, given that known time-varying injection rates are applied. We propose a mixture model to characterize the lag time for each injector-producer pair, where the system is initialized by assuming that multiple candidate fractures exist. Our algorithm iteratively modifies the length, orientation and location of each high permeability candidate in order to match the measured response time between wells. It is well known that the solution may not be unique if we only have limited measurement data. Thus, in order to choose between possible models, we propose to use the "total length" of high permeability channels as regularization metric. Our method will select the model that fits the measured lag time with minimum total high permeability channel length. It is also possible within our framework to adjust the regularization so that it takes into consideration other type of prior information, e.g., preferred orientation known to exist in a given field.
To validate our approach, we use a commercial simulator to test a synthetic line drive and a 5-spot waterflood. In the first case, we test a five spot with hydraulic fracture located in the central production well.
In the second case, we test a single fracture with 45 degree orientation located between rows of producers and injectors. Our results show that our method can provide very accurate estimates of fracture orientation, with decreased uncertainty as the well density in the field increases.