bluuebunny/crossref_metadata_2025_split huggingface dataset:
World's First Combination Of Acid & Steam Provides A New Dimension To Heavy Oil Enhanced Recovery Process
Authors: Shaheen Tarek , Hassan Wael , Siddiqqi Irfan , Kamal Salah 
Published: April 2012

Abstract
The Issaran field located 200 km east of Cairo-Egypt, is a heavy oil reservoir. The oil is of 8-12 degree API with viscosity of 4000 cps at standard conditions.
Productivity of the wells has sharply declined due to increase in the water cut and increase in the formation skin value. The problem is attributed to the heterogeneity of the reservoir together with presence of fractures which is causing poor sweep efficiency plus the accumulation of hydrocarbon deposits.
The major challenge to remedy this situation was; 1) The creation of new extended flow channels. 2) Accurate placement of the treatment. 3) Diversion within the reservoir. 4) Provide sustain production increase. And 5) The flow and the production of oil through the newly formed wormholes.
A new innovative approach using a combination of acid based treating fluids and steam were used. Acid in combination with fit for purpose chemical diverting agent plus selective placement mechanism succeeded to open new production horizons and stimulate the existing one. The Addition of Steam has succeeded in reducing the viscosity and increasing the mobility of oil, and also in providing pressure support to the reservoir achieving further increase in the benefits of the acid stimulation.
The results of the treatments carried out so far have provided a new dimension in the enhanced recovery process of the heavy oil. This paper explains the design, execution, evaluation and the recommended way forward of this world first acid & steam production enhancement initiative for enhanced recovery process in the heavy oil reservoirs.
Potential For Inhibitor Squeeze Application For Silicate Scale Control In ASP Flood
Authors: Sonne Jennifer , Miner Kirk , Kerr Scot 
Published: April 2012

Abstract
Alkaline surfactant polymer (ASP) floods often induce silicate scaling. Scaling of the production tubing, rod pumps and other surface equipment causes frequent workovers, resulting in increased costs and non-productive time. High treatment rates and short run times drove the re-evaluation of the problem in pursuit of more targeted products and applications. The formation of silicate scale is complicated by its dependence on multiple water chemistry-dependent factors which vary as the flood progresses (Gill 1998). These factors affect silicate scaling tendency, and consequently, severity of the problem. A range of silicate scale inhibitors has been developed to mitigate problems in oilfields afflicted with silicate scaling due to ASP flooding (Qing et al. 2002). A new test method using an optical scanning device was developed to better characterize inhibition and dispersant qualities of inhibitors on silicate scale in solution under static conditions. The advantage of this method is more comprehensive data generated by multiple-point measurements. Scaling reactions are more easily modified and differentiated. Water chemistries from several wells in an ASP-flooded field in Southern Alberta with known silicate scaling issues defined the tested synthetic brine. By allowing the mixed synthetic brine to react before adding inhibitor, the effect of delayed chemical injection may be studied. Performance of the tested inhibitor was significantly reduced by slight injection delay and may account for the discrepancy often seen between laboratory performance data and failures observed in the field. It is proposed that the performance of silicate scale inhibitors may be improved when applied by squeeze, where the inhibitor can inhibit silica polymerization within the formation and may provide substantial improvement over conventional continuous down-hole injection. Test work done to confirm the feasibility of the squeeze included fluid compatibility and core damage studies. These performance tests demonstrated the treating advantages of a scale inhibitor squeeze.
Water Injection Subsurface Challenges and Reactive Transport Modelling
Authors: Al Mayahi Najma , Snippe Jeroen , Rucci Facundo , Linthorst Steef 
Published: April 2012

Abstract
Two main development options were identified for a carbonate stringer reservoir being waterflood and Miscible Gas Injection (MGI). The waterflood project economics were more favourable; however potential showstoppers were identified. The key risks associated with waterflooding this reservoir are halite precipitation, anhydrite swelling, injectivity loss and the quality of produced water.
Faced with this challenge the study team started dedicated studies on rock integrity, water compatibility and scaling mitigation in order to assess and moderate these risks. Reactive Transport Modelling (RTM) work was initiated. The Reactive Transport Model is a reservoir simulator coupled with geochemical simulation. The objective of the model is to quantify reactions between rock and fluid, and forecast pH and salinity over time at the producer. This is dependent on data obtained from core flood experiments, and H2S and CO2 solubility data obtained from literature review and thermodynamic modelling. In order to calibrate the models the following studies and experiments were initiated:Literature reviews (i.e analogues for waterflooding in sour fields, anhydrite swelling, and H2S (and CO2) solubility in brine);Core flood experiments for temperature and salinity range and halite dissolution with the objective to get dissolution rates as a function of surface area, temperature and salinity;In addition a field injectivity trial was executed to proof injectivity and calibrate the models
Significant work has been done on the subsurface risks associated with waterflooding. This integrated and dedicated study has contributed at large to the project’s key decisions. A key conclusion from the study was that anhydrite to gypsum conversion is unlikely to pose a risk to well integrity or injectivity hence there is no need to heat the injected water. This resulted in a saving of $160 mln on operating costs. For halite scaling, the formation water bank poses a higher risk than mineral (halite) dissolution in the reservoir. Hence jet pumping was selected as a lifting mechanism providing also flow assurance.
Developing a Layered Heterogeneous Precambrian Reservoir by Polymer Flooding
Authors: Abu-Shiekah Issa , Nieuwenhuijs Robbert A , Ross Ryan , Lanier Gary , Belushi Abdulaziz , Saadi Faisal , Nofli Sami , Harthi Said , Van Wunnik John 
Published: April 2012

Abstract
Enhanced oil recovery through injection of a solution of water and polymer is becoming a mature chemical flooding technique. In general, reservoirs with mature water-flooding projects offer an excellent opportunity for extension with polymer injection as uncertainties associated with reservoir connectivity and injection potential are already substantially reduced. For our particular reservoir an additional fortunate circumstance includes an ongoing polymer injection project in an adjacent reservoir which enables easy field testing given the local operational challenges and circumstances.
This paper presents ongoing work related to improving ultimate oil recovery from an active water flood project by polymer injection where a polymer flooding pilot is already ongoing. The work includes studies to extend the existing polymer injection facilities of a nearby polymer project to this rather different, in geologic terms, Precambrian reservoir with much lower permeability, oil saturations and significantly more layered reservoir architecture. Geological and petrophysical workflows together with dynamic modeling history matching iterations resulted in reducing subsurface uncertainties such as the distribution of permeability and initial oil saturation. Reservoir compartment connectivity and sweep efficiency are constrained by matching pressure and injection, as well as, production data from 180 wells. Polymer injection feasibility is proven through: dynamic modeling, laboratory experiments, ongoing polymer injection pilot and adapting learning’s from the ongoing adjacent polymer project. The study reveals that a polymer injection project is economically feasible under a range of subsurface and costs scenarios.
Water-Based Enhanced Oil Recovery EOR by "Smart Water" in Carbonate Reservoirs
Authors: Fathi S. Jafar , Austad Tor , Strand Skule 
Published: April 2012

Abstract
Water chemistry has a profound effect on the stability of the water film and desorption of organic oil components from the mineral surfaces in a water—based enhanced oil recovery (EOR) process. By knowing the chemical mechanism for the symbiotic interaction between the active ions in seawater; Ca2+, Mg2+, and SO42—, "Smart Water" can be designed and optimized in terms of salinity and ionic composition as an EOR—fluid. In the present study, the efficiency of "Smart Water" on oil recovery in carbonate rock is summarized and discussed in the temperature range of 70—120 °C. By removing non–active salt, NaCl, from the composition of the injected seawater, the oil recovery by spontaneous imbibition was improved by about 5–10% of OOIP compared to seawater. On the other hand, an increase in the concentration of NaCl in the imbibing fluid resulted in reduced oil recovery of 5% of OOIP. A systematic decrease in oil recovery was observed when diluting seawater with distilled water to obtain a low salinity brine, 1000–2000 ppm. The decrease in the oil recovery was attributed to the reduced concentration of the active ions. When seawater depleted in NaCl was spiked by SO42–, the oil recovery increased by about 5 to 18% of OOIP compared to seawater depleted in NaCl. The amount of Ca2+ in the seawater depleted in NaCl had no significant effect on the oil recovery at low temperatures, ≤100 °C, but improvements were observed at higher temperatures. The wetting condition after spontaneous imbibition of seawater, seawater depleted in NaCl, and seawater depleted in NaCl spiked with sulfate was monitored using a chromatographic wettability test, and it showed an increasing order in the water–wet fraction, in line with increased oil recovery. The results were discussed in terms of the previously suggested mechanism and the effect of the ionic double layer at the rock–brine interface.
Heavy Oil Secondary Production Optimization - Successful Application of New Horizontal Well Drilling Pattern Strategy and Fit for Purpose Technology in Nearly Obsolete Mature Heavy Oil Reservoir in North East China
Authors: Xiang Ren Fang , Yan Sun , Zhong Yu Tian , Zhao Fan Hong , Yun Lv Jian , Halomoan Parlindungan Monris , Bin Yang , Hui Xu Chong , Xie Roc Xiaopeng , Ruo Wang 
Published: April 2012

Abstract
XH27 is a heavy oil reservoir with a high oil/water viscosity ratio that incurs bottom water coning effects. To enhance the primary heavy oil production, 59 vertical wells with a 141-m square well pattern have been drilled since 1992. The highest primary oil production of 360 tons/day was reached in 1994. Starting in 1996, the reservoir fell into a significant production decline phase. The reservoir was on the brink of obsolescence in 2006 when a 93.6% water-cut discharge and a 0.26% annual oil recovery factor were recorded.
Based on detailed static reservoir characterization and updating of the dynamic reservoir model, the square vertical well pattern development strategy was shifted to a horizontal well drilling venture with a net-remaining-oil-distribution pattern. The major shortcoming to overcome was accurate placement of the horizontal section trajectory close to the reservoir top for the injector-producer wells. The thin oil-column target of less than 5 m added to the challenge.
To overcome these challenges, real-time well placement monitoring using high-resolution resistivity images, along with near-bit measurements, has been applied in all horizontal wells drilled. Clear identification of structural dips enabled the accurate reservoir model adjustment and allowed decisions on accurate trajectory corrections to be made while drilling.
A total of 33 horizontal injector-to-producer wells have been executed successfully. Three years from the inception of the new strategy, the average secondary production improved to 380 tons/day, which is higher than the best daily production during the course of primary production. The oil recovery is expected to double.
The application of the new horizontal well drilling pattern strategy, along with fit-for-purpose well placement technology, in the XH27 heavy oil reservoir has significantly increased the oil production and enhanced the recovery factor. The nearly obsolete heavy oil reservoir can be turned into an economically developed field.
Time-Lapse Diffusion Logs to Discriminate Reservoir Oil from Miscible Gas
Authors: Edwards John , Mutina Albina , Cheng Yuesheng , Gao Jinglin , Fordham Edmund , Freed Denise , Bachman Nate , Dolan Sean , Al Rashdi Yaqoob , Wilson Ove Bjorn , Haynes Byron , Looyestijn Wi m 
Published: April 2012

Abstract
A carbonate light oil reservoir surrounded by salt is without an active water or gas cap. The reservoir energy is limited. Without miscible gas flooding the initial production will drop quickly and the ultimate recovery is expected to be 10%. With miscible gas flooding the recovery is hoped to be in excess of 30%.
Oil desaturation measurements in observation wells near the injectors may give an early proof of this hypothesis, providing information on the miscible gas front and the efficiency of the sweep. However, the contrast between the reservoir oil and rich injected gas is small for monitoring with conventional cased-hole nuclear measurements. Cased-hole resistivity will not help, because the water saturation is low and not expected to change. An effort was made to qualify another measurement that could distinguish the two fluids to supplement the conventional logs: the diffusion of polarized hydrogen. The hydrogen associated with the longer chain molecules in the oil diffuses slower than the lighter hydrogen in the injected gas. Measuring the diffusion distribution of a hydrocarbon composition is possible with nuclear magnetic resonance (NMR).
A diffusion model was created using the liquid and gas compositions that were predicted using a PVT model as the proportion of injected gas to native oil was increased. This diffusion distribution indicated the liquid and gas phases could be distinguished and were therefore separately measurable for all the proportions modeled. This was verified with an NMR laboratory measurement of bulk fluids at various oil and gas proportions at reservoir conditions. The carbonate formation in this reservoir is characterized by heterogeneity; permeability variations of two orders of magnitude, and wide pore-size distribution. The hydrogen diffusion that is intended to discriminate the two fluids is partially suppressed in the formation pore volume due to restricted diffusion. The second phase of laboratory experiments consisted of quantifying the effect of the 90% dolomite 10% anhydrite rock on the diffusion of gas and liquid when constrained by the formation pore structure. The gas phase diffusion was reduced by a factor of four, and the liquid phase diffusion was reduced by 10%. Even with these reductions there was only little overlap of the diffusion distributions between the live reservoir fluid and injected sour gas that saturated the core plugs of porosity 21, 15, and 7. Laboratory tests also validated the NMR-transparency of special casing at reservoir conditions.
EOR Field Management Through Well-Planned Surveillance
Authors: Zwaan Marcel , Hartmans Rob , Schoofs Stan , de Zwart Bert Rik , Rocco Guillermo , Adawi Rashid , Saadi Faisal , Shuaili Khalfan , Lopez Jorge , Ita Joel , L’Homme Tanguy , Sorop Tibi , Qiu Yuan , van den Hoek Paul , al Kindy Fahad , Busaidi Said , Fraser John 
Published: April 2012

Abstract
PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs.
However, the interpretation of this advanced surveillance data and integration into well and reservoir management workflows is still challenging. This paper describes the results of the integrated workflows for the interpretation, modeling and integration of surveillance data in four EOR projects. The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through time lapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging. This paper shows that the surveillance has contributed to the understanding of recovery mechanism in a pattern steam flood, it has supported decisions well-recompletions and work-overs and it has supported decisions on injection rates and surveillance planning in the chemical flood project.
Enhanced Computer-Assisted Model Calibration of Mukhaizna Heavy Oil Field
Authors: Pillai Taruna , Isdiawan Agusandi , Al Kindy Dalilah 
Published: April 2012

Abstract
The Mukhaizna field is a giant heavy oil field under steamflood for the past four years. A sector with NW-SE elongate low relief anticlinal structure from a complex full-field geological model with 200,000,000+ cells of channelized braided-fluvial sandstone deposition was upscaled to a dynamic model with 400,000+ cells. This sector model approximately 15% of the field production area, from the crestal part of the field comprises 87 producers and 78 Limed Entry Perforated injectors with several years of production and steam injection history.
A precursor for almost every reliable production forecast is a good history matched simulation model which becomes the cornerstone to optimize the decision making process. This paper describes an integrated and comprehensive simulation modeling workflow which was implemented to incorporate geological, petrophysical and dynamic uncertainties in a systematic way to calibrate the simulation model. Sensitivity analysis was performed to identify key static and dynamic input parameters. A computer assisted optimizer which applies experimental design and Tabu search techniques was used to test nonlinear and interaction effects of about 25 input parameters. This could be practically impossible using traditional sequentially modifying one-variable-at-a-time approach which always is cumbersome and may skew into an apparent solution even when none exists. During the iterative history matching process, uncertainties related to input parameters were constrained and modified from time to time to get an optimal solution. In addition to history matching 165 production/injection wells and 35 wells with pressure data, an attempt was made to match temperatures in 13 observation wells as well as heat breakthroughs in 70 patterns. The use of advanced techniques allowed us to minimize number of simulation runs and significantly reduced time to complete model calibration in less than couple of months which could traditionally take more than a year and still be limited in efficiently testing all possible combinations of input parameters.
Flow Characteristics of Viscoelastic Polymer Solution in Micro-Pores
Authors: Yin H. J. , Wang D. M. , Zhong H. Y. , Meng S. Y. , Jiang H. M. , Tang E. G. 
Published: April 2012

Abstract
Most experimental results demonstrate that the first normal stress difference of viscoelastic polymer solution is higher than the second normal stress difference. Therefore, the Upper-Convected Maxwell (UCM) equation is adapted to describe this property. The steady flow mathematical model of UCM fluids is established. The simulation results of the Finite Volume Method are given. The Finite Volume Method can effectively ensure the convergence together with improvement in the calculation accuracy. The Weissenberg number (We) of the Finite Volume Method can be calculated to 3.2, which is higher than by the Finite Differential Method to simulate the flow characteristics of polymer solutions. When using the Finite Differential Method, the Weissenberg number can only be less than 0.4, otherwise it cannot converge.
The contours of stream function and velocity of polymer solution with different Weissenberg number (We) or Reynolds number (Re) are drawn in three simplified micro-pore structures, expansion channel, contraction channel and expansion-contraction channel, respectively. The influence of Weissenberg number (We) and Reynolds number (Re) on microscopic sweep efficiency is studied. Numerical results show that the viscoelasticy of polymer is the main property that increases the sweep efficiency. With the increase in elasticity, the solution velocity of micro-pores at the corner of where the diameter suddenly changes is bigger; the flow region is enlarged, which is favorable for the residual oil becoming moveable, thereby increasing the micro-scale sweep efficiency. The higher the Reynolds number (Re) is, the larger the micro-scale sweep efficiency will be. But in reservoir condition, Reynolds number (Re) has little influence on improving the micro-scale sweep efficiency.
The above results are important to further understand the mechanism of driving fluid viscoelasticity increasing the Displacement Efficiency of porous medium.
Improving Sweep Efficiency in Fractured Carbonate Reservoirs by Microbial Biomass
Authors: Al-Hattali R. , Al-Sulaimani H. , Al-Wahaibi Y. , Al-Bahry S. , Elshafie A. , Al-Bemani A. , Joshi S. 
Published: April 2012

Abstract
Selective plugging by microbial biomass is one of the proposed mechanisms for improving reservoir sweep efficiency in fractured reservoirs. In this study, the potential of Bacillus licheniformis strains isolated from oil contaminated soil from the Sultanate of Oman was tested for their ability to grow in induced fractures in carbonate rocks and to divert subsequent injection water to the unswept matrix zones.
Three Bacillus licheniformis strains were tested with name codes; B29, B17 and W16. Their growth behavior using different nitrogen sources; yeast extract, peptone and urea was investigated. Glucose and sucrose were tested as carbon sources. Carbon/nitrogen ratios were optimized where it was found that sucrose was the carbon source that maximized bacterial growth at 2% concentration and yeast extract was the selected nitrogen source with concentration of 0.1%. The combination of B. licheniformis strain W16 in a minimal medium containing sucrose was the optimum condition for maximum cell growth within 10-12 hours of incubation. Standard Indiana limestone core plugs were used for coreflooding experiments where a fracture was simulated by slicing the cores vertically into two sections using a thin blade. The bacterial cells were injected into the cores and the ability of the microbes to grow and plug the fracture was examined. Scanning electron microscopy was used to prove the growth of the microbial cells in the fracture after the experiment.
Coreflooding experiments showed promising results where enhancement of oil recovery was observed after bacterial injection. A total of 27-30% of the residual oil was produced after 11 hours of incubation. This shows the high potential of using microbial biomass for selective plugging in fractured reservoirs.