bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Numerical Method for 3-Dimensional Fluid Front Investigation for Long Horizontal Wells Using Pressure Transient Analysis
Authors: Gilani Syed Furqan , Tarsauliya Gunja , Bennetzen Martin V. , Evans C. 
Published: March 2016

Abstract
This paper presents a 3-dimensional numerical simulation approach and derivation of a simple analytical expression to track the fluid fronts using pressure transient analysis in long horizontal wells. In general, fluid front tracking studies are rarely used for horizontal wells. In the past, analytical models, such as radial composite model, have been used to estimate fluid front distance, which do not account for changed mobility due to different fluid saturations and relative permeabilities. The main assumption for an analytical model is to consider constant mobility for flooded and un-flooded reservoir regions. Hence, an appropriate methodology for fluid front estimation would be numerical analysis of pressure transients.
The study has been conducted for a homogeneous and low permeability artificial reservoir with long horizontal wells. The results show that changes in fluid properties at flood front cause a slope change in pressure response. An equation has been derived to calculate the distance to the flood front (diagnosed as a slope change), which follows the form of the standard equation for radius of investigation. The equation includes a constant ‘A' which is possibly dependent on permeability of the reservoir and relative permeabilities of the fluids. Various sensitivities have been performed to understand the dependency of the constant ‘A' on reservoir and fluid properties. In addition, it is shown that the constant ‘A' does not vary significantly with porosity, viscosity, reservoir thickness, well length and total compressibility of the system.
With a properly designed program for acquiring pressure transient data combined with the presented methodology, distance to fluid fronts can be estimated with reasonable accuracy.
Successful Field Test of a New Polymer Flooding Technology for Improving Heavy Oil Reservoir Recovery -- Case Study of Strongly Heterogeneous and Multi-Layer Conglomerate Heavy Oil Reservoir XJ6
Authors: Wu Xingcai , Zhang Song , Xiong Chunming , Liu Shunsheng , Cai Cheng , Zhao Meigang , Yu Zhentao , Li Bin , Xu Hanbing , Wu Yongfeng , Yang Ning , Ye Yinzhu , Tian Xiaoyan , Chen Jingjing 
Published: March 2016

Abstract
XJ6 is a conglomerate reservoir, with oil viscosity 80mPa.s. It is similar to carbonate reservoir that the formation sedimentation does not show obvious rhythm. The pore structure and size varies greatly, with dual and complex porosity and permeability distribution, causing seriously uneven sweeping. Traditional polymer flooding technology is not suitable. A pilot test, conducted in 2013, used a new particle-type polymer, combining several small polymer gel slugs, obtaining obvious oil rate increase and water cut decrease.
Cores were sampled from 8 sealing core drilling wells. The casting core film images were analyzed, and the microscopic structure of formation pores was studied. The pore size and distribution were quantitatively characterized by mercury injection testing data, and also predicted by geology modeling. The macroscopic water flowing channel distribution and volume were quantified through numerical simulation and tracer test, based on which, the combined slug parameters of polymer flooding were designed.
There are 5 injectors and 11 producers in the pilot. Related testing results show that the water flowing velocity between injector and producer varies with big difference, 17 times, and the highest velocity is 27.7 m/d. It is developed with wide range of pore radius, 1.72-354.6μm. To control water cut rising, injection and production rates were kept at low value. The remaining oil distributed in complex porosity and permeability zones was hard to be initiated. The injection plan was alternating injecting the slugs, consisting of big slug of the new particle-type polymer dispersion with particle size in the grade of micrometer, and small slug of crosslinked polymer. The injection liquid amount is 0.2PV. One month after the test started, the water cut of the pilot began to decrease fast and the daily oil rate began to increase fast. The daily oil rate was increase to 62.2 t/d from 16.1 t/d, and the water cut was decreased to 35.8% from 82.0%. The center well got better effect. The average injection pressure of the pilot was increased by 2MPa. The daily water injection rate and daily liquid production rate were increased by 20% gradually.
By the pilot test, the new oil displacing mechanism and slug design method were explored, achieving a success. It was shown that, for conglomerate reservoir with complex formation pore structure and large pore size difference, with the previous slug of highly viscous polymer gel to inhibit the large channels, taking the new submillimeter/micrometer grade particle-type polymer slug can favor displacing the remaining oil.
Can Associative Polymers Reduce the Residual Oil Saturation?
Authors: Reichenbach-Klinke Roland , Stavland Arne , Strand Daniel , Langlotz Björn , Brodt Gregor 
Published: March 2016

Abstract
The oil recovery potential of acrylamide-based, associative thickening polymers has recently been evaluated in a coreflood study of our department. Associative polymers are anionic, water-soluble copolymers modified with varying degress of pendant hydrophobic groups. By intermolecular interactions of these hydrophobic moieties a fully reversible network of polymer coils can be formed.
The oil recovery efficiency of a series of copolymers based on acrylamide, 2-acrylamidopropane sulfonic acid (ATBS) in combination with a hydrophobic comonomer has been determined in linear coreflood experiments at a temperature of 60°C. Synthetic sea water was used as brine and Bentheimer sandstone as core material. The evaluated polymers differed in molecular weight and associative groups' content.
While anionic polyacrylamide (APAM) shows very similar resistance factors (RF) in coreflood experiments with and without oil, a significantly reduced RF in the presence of oil has been found for the associative polymers. The magnitude of this decrease in resistance factor was dependent on the specific type of associative polymer.
The effect can be ascribed to the weakend intermolecular interaction of the hydrophobic groups in the associative polymers in the presence of oil. Even though the RF value is reduced in the presence of oil, it still remains higher than that of regular APAM.
At low flow rates representing reservoir conditions a high resistance factor was observed and oil production was improved. This observation can be explained by an increase of the capillary number caused by the high RF of the polymer drive. A good correlation between oil production and capillary number was established.
Permeability reduction effects explained the high mobility reduction observed with the associative polymers, as the bulk viscosity data did not correlate with the in-situ flow properties of the polymers in porous media.
Evaluation of Mixing in Low Salinity Waterflooding
Authors: Attar Ahmed , Muggeridge A. H. 
Published: March 2016

Abstract
The impact of heterogeneity induced mixing between the injected low salinity water and the high salinity connate water is investigated in secondary low salinity waterflooding (LSW). Although LSW has proved to be a promising EOR process in laboratory experiments and field trials, its efficiency can be reduced due to mixing with in situ higher salinity connate water. This mixing is caused by molecular diffusion and dispersion and it has been suggested that it may be exacerbated by heterogeneity.
We have investigated the impact of 1) conformance caused by layering in the sandstone and 2) mixing caused by water-saturated shale layers adjacent to the reservoir sand on recovery. The study used a commercial reservoir simulator in which low salinity flooding is modelled by varying relative permeability as a function of salinity. All simulations used very fine grids so that physical (rather than numerical) diffusion and dispersion dominated the displacement. In single phase flow, it was found that physical dispersion can only be modelled for when the grid Peclet number is less than 60, for higher values numerical dispersion dominates over physical values. This threshold Peclet number varies with the number of grid blocks, e.g. the optimum number of grid blocks was found to be 10 for (Pe &lt;12) compared with 1000 grid blocks (Pe = 60).
The transverse dispersion number (NTD) originally proposed by Lake and Hirasaki (1981) is shown to be a very robust way to measure the impact of mixing on the performance of LSW. Generally, for any (NTD &gt; 1), diffusion dominates the flow and thus the efficiency of LSW is reduced. In layered high net to gross reservoirs mixing can actually improve recovery from low salinity water flooding and we find that the impact of molecular diffusion increases as the thickness of the higher permeability layer decreases. In lower net-to-gross reservoirs containing thin, shaly zones filled with higher salinity connate water molecular diffusion reduces the effectiveness of LS. This performance reduction is more noticeable as the thickness of the sand layers between the shales decreases.
CT-Scan Monitoring of Combined Chemical EOR Processes in Fractured Carbonate Cores
Authors: Rosenberg E. , Robin M. , Bourbiaux B. , Chabert M. , Chevallier E. , Gautier S. 
Published: March 2016

Abstract
Almost 60% of global oil reserves are contained in carbonate reservoirs. A large number of those are naturally fractured and oil- or mixed-wet. Waterflooding efficiency is often very low for such reservoirs because of both high fracture-to-matrix permeability contrast and unfavorable wettability. The recovery of the oil trapped in the matrix is then very challenging. To enhance this recovery, several recovery mechanisms can be assessed: –capillary imbibition by using wettability modifiers,–viscous drive by imposing a pressure gradient in the fracture network,–water-oil gravity drainage by using low IFT surfactants formulation.
This paper presents an experimental approach that evaluates different chemical EOR alternatives using one or several of the three previous recovery mechanisms. The experiments consist in injecting an aqueous chemical solution or a foam containing chemical additives into an artificially fractured carbonate core. The imbibition is monitored with a recent CT-scanner allowing the local quantitative monitoring of three phases, including accurate quantification of matrix oil recovery. This paper is mainly focused on the impacts of foaming agents and of wettability modifiers, implemented separately or jointly. The experiments have also been conducted on several cores of different permeability, resulting in various permeability contrasts between matrix and fracture.
A major result concerns the kinetics of oil recovery by chemical additives, that is greatly increased when a viscous drive is applied across the matrix medium via the circulation of foam in the fracture. Experiments in fractured cores of different permeabilities indicate that foam does not penetrate the matrix but drives the chemical aqueous phase into the matrix due to the generated pressure gradient. Detailed analysis of oil mobilization dynamics is provided. These foam flow experiments are compared with former chemical imbibition tests on non-fractured cores, for further insight of the role played by viscous forces. The comparison of tested recovery scenarios leads to conclusions regarding optimal chemical EOR strategies for naturally-fractured carbonate reservoirs with poor secondary recovery prognosis.
Solvent Enhanced Steam Drive: Results from the First Field Pilot in Canada
Authors: Castellanos-Diaz O. , Verlaan M. L. , Hedden R. 
Published: March 2016

Abstract
A solvent enhanced steam drive pilot has been executed in the Peace River area in Canada, where co-injection of steam and solvent was deployed in two inverted 5-spot 5-acre steam drive patterns. The results were compared to two adjacent patterns were only steam was injected. The pilot involved extensive metering and sampling surveillance during 1.5 years. After several months of starting the steam drive a large slug of solvent was injected, subsequently followed by steam drive. Several challenges emerged with respect to data accuracy and acquisition, inherent to the first deployment of this technology and of the pilot being a brown field project. To overcome these issues, a data uncertainty management plan was made aided by reservoir simulation. The pilot demonstrated significant bitumen uplift due to solvent injection and solvent recovery from the reservoir in line with expectations. A reservoir simulation model with sound physical principles was constructed confirming bitumen uplift estimates and solvent recovery trends seen in the field.
Low Tension Water Flood (LTWF) for Enhanced Oil Recovery in a Tight Carbonate Oilfield
Authors: Al-Rubkhi A. A. , Karimi M. , Hadji M. , Al-Maamari R. S. , Aoudia M. 
Published: March 2016

Abstract
The aim of this study is to develop and optimize a low tension water flood (LTWF) as an option for enhanced oil recovery in a tightcarbonate oilfield using a mixture of formation brines as injection water (total salinity: 165.9 g/L, Ca2+: 12.3 g/L, Mg2+: 2.0 g/L, and T = 70 °C.). In our approach, a combination of an anionic surfactant (alkyl ether sulfonate, C17EO7S(C17EO7) and a nonionic surfactant (alkyl ether, iC13EO10) were used to formulate clear and stable surfactant solutions at reservoir conditions.
Formulation and optimization of a LTWF at a very low total surfactant concentration (0.01 wt%) was achieved through surfactant/brine compatibility tests (target: clear and stable surfactant solution), surfactant solution/oil interfacial tensions (target: ~ 10-3 mNm-1), phase behavior (target: type II(-) oil-in-water microemulsion) and core flooding experiments.
Compatibility tests showed that the cloud point of the nonionic surfactant (0.01 wt%)is lower than the reservoir temperature (70 °C) whereas the clear point of the anionic surfactant is above the boiling point of water, suggesting that both surfactants cannot be used alone at reservoir conditions. On the other hand, clear and stable mixture of anionic/nonionic surfactants in the composition range fw = 0.1 – 0.8 (fw being the weight fraction of the nonionic surfactant) at 0.01 wt% total surfactant concentration were generated above 70 °C.
Clear, transparent and gel-free oil-in-water phase behavior with relatively high oil solubilization parameters (σo ~ 125) were observed for surfactant mixture (0.01 wt%, fw = 0.1-0.8). These phase behaviors tests were validated by interfacial tension (IFT) measurements. Ultralow IFT (~ 10-3mN/m) was achieved at fw = 0.2. This optimum system was selected for core flooding experiments. Injecting surfactant (0.5PV) slug into a fully water flooded carbonate core sample resulted in additional oil recovery of 10 % of OOIP. This is a very significant result owing to the low surfactant concentration used (0.01 wt%). In another experiment, injecting a surfactant slug (0.5 PV) before water injection resulted in a total recovery of 75% of OOIP. In addition, Amott-Harvey test showed that wettability indices of the core plug samples used in the experiments changed within a narrow range (– 0.231 to + 0.164); suggesting an alteration of wettability from slightly oil-wet to weakly water-wet state.
Monitoring IOR/EOR Onshore with Frequent Time-Lapse Seismic - Status and Survey Adaptations for the Middle East
Authors: Mateeva A. , Hornman K. , Grandi S. , Potters H. , Lopez J. , Follett J. La 
Published: March 2016

Abstract
IOR/EOR stimulation is a complex process that requires frequent areal monitoring to optimize recovery. On-demand seismic surveys are a suitable solution if cost, quality, environmental, and efficiency conditions are met. In this paper, we discuss the state of the art.
We show that frequent buried seismic has the necessary quality and was able to add value to steam injection operations at a heavy oil field in Canada. However, in its current form, buried seismic is too expensive and intrusive. That is why, for future deployments, we seek cost and footprint reductions through judicious reduction of survey frequency (from days to weeks or months apart) and novel survey designs such as a buried cross-spread with Distributed Acoustic Sensing (DAS) receivers and movable subsurface sources. We are in the process of maturing the buried cross-spread solution. Its application to some extreme settings found in the Middle East (deep reservoirs with weak seismic expression under thick and complex overburden) is expected to be challenging. A promising alternative already available is 4D VSP with DAS in multiple wells. This solution requires sufficient surface access, fiber optic cables in wells, and skillful seismic processing.
Improving Polymer Flooding Efficiency in Oman Oil Fields
Authors: Al-Hashmi A. R. , Divers T. , Al-Maamari R. S. , Favero C. , Thomas A. 
Published: March 2016

Abstract
Considering a depressed environment with low oil prices, optimizing the costs linked to polymer injection becomes important. In this paper, the efficiency of two polymers dedicated to Omani southern fields’ conditions have been evaluated: a standard copolymer currently injected in the Marmul field and another polymer optimized in terms of chemistry and polymerization process. The purpose is to ensure that changing the polymer will not impact the project efficiency. Consequently, the rheological properties, long term stability and injectivity have been compared for both polymers.
The standard polymer (P1) is a high molecular weight polymer widely used worldwide. The new polymer (P2) is a higher molecular product with better salinity and temperature resistances. In terms of rheological properties, P2 displays a higher viscosity in the field brine and also displays better viscoelastic properties with, in the end, a significant decrease of polymer dosage. Filterability of the polymer P2 is slightly poorer than for the P1, which is likely due to a higher molecular weight. P1 and P2 injectivity properties were assessed in two different cores: 100 mD Berea cores and 1500 mD Bentheimer cores. Both polymers propagate quite well in both core types showing no injectivity issues after injection of 4 to 5 pore volumes. In the Berea core, adsorption was approximately 42 µg/g for the P1 and 25 µg/g for the P2. Permeability reduction was nevertheless quite significant in such low permeability cores, and some face plugging was observed. In 1500 mD cores, adsorption valuewas determined around 12 µg/g and 10 µg/g for the P1 and the P2, respectively. Thermal stability for both polymers was performed in fully anaerobic or with specific amounts of O2 and H2S. The efficiency of two protective packages against H2S induced degradation was evaluated. The results after the incubation for 4 months highlight the need to avoid oxygen ingress in the system in presence of H2S. However, it is still possible to keep an acceptable level of viscosity by fine-tuning the protective additives.
This study demonstrates the viability of a cost-effective alternative to what is already used in the Marmul field. This new polymer can be an appropriate candidate to keep chemical EOR in Omani southern fields economically viable.
An Integrated Rejuvenation Project in the UK. From Gas Disposal Issue to WAG Opportunity
Authors: Manotti M. , Renna S. , Mattei M. , Foglio G. , Mariotti P. 
Published: March 2016

Abstract
Despite the increase of hydrocarbons exploitation from green fields in the last decades, the majority of the global production is still sustained by brown fields contribution. Rejuvenation of mature assets, as the one described in this work, plays a crucial role in current low oil price scenario, improving production with limited investments and risks.
Object of this work is an offshore oil field in the UK area in production since 1996. The field is developed by means of water injection for pressure maintenance and gas injection for disposal, with current water-cut higher than 90% and gas-breakthrough in wells close to the disposal area. After the acquisition of the operatorship in 2014, an asset rejuvenation project started, involving an integrated analysis of the field, based on the review of all available static and dynamic data. Combination of basic reservoir engineering tools and advanced modeling simulators was the key element of the performed analysis. This paper shows how an integrated workflow, combining skills from different professional families, allowed to find low cost opportunities with short time-to-market.
Production data analysis highlighted low efficiency of current water injection: majority of the injected volume is produced without displacing additional oil. Moreover, the new reservoir compositional model showed presence of by-passed oil in the crestal part of the field not displaced due to gravitational segregation effect.
Thanks to the better understanding of the field characteristics and fluids movement, different actions were planned in order to maximize oil recovery. In particular, a screening of possible IOR/EOR techniques showed immiscible WAG as the most promising one to recover un-swept attic oil. Several sensitivities were performed on water and gas injection rates, cycles duration and gas composition, in order to properly evaluate and maximize the expected additional recovery. Based on modeling results, two currently shut-in injectors were selected for a WAG pilot phase. The feasibility study highlighted that only minor plant changes were required, due to the availability of both water and gas injection facilities. This aspect drove the project economics into favorable evaluation. Moreover, moving gas injection from disposal to WAG mitigates well production problems in the disposing area, turning gas injection from an issue to opportunity extending field life.
This paper gives a detailed description of the rejuvenation project ongoing on an UK field which main outcome is the start-up of a WAG project. Advanced workflow, combining streamlines and conventional simulators, was used for waterflooding assessment and optimization. This integrated project was carried out with short time to market and minimal expenditure, showing how EOR processes can be an opportunity for field rejuvenation even in a low oil price environment.