bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Systematic Study of the Polymer Visco-Elastic Effect on Residual Oil Saturation by Core Flooding
Authors: Vermolen E. C. , Haasterecht M. J. , Masalmeh S. K. 
Published: June 2014

Abstract
The decrease in the residual oil saturation by polymer flooding with a high visco-elasticity solution has been widely addressed in the past few years. The effect of the polymer solution visco-elasticity on the microscopic sweep efficiency was studied experimentally in a range of length scales, from micromodels through core floods to full field application. In most of the micromodel and core flooding experiments, a comparison was made between the effect of glycerol and polyacrylamide solutions on the oil recovery, because glycerol does not exhibit elastic behavior (only viscous), while polyacrylamide solutions do.
In this paper it is discussed that the use of glycerol in combination with brine and/or polymer solutions could yield erroneous results due to a very strong dependence of the glycerol viscosity on temperature and on mixing with water. Instead, in the current study a series of core floods was done in which several polymer solutions were injected with a wide spread in viscoelasticity but the same apparent viscosity to study the effect of visco-elasticity on oil recovery.
The main conclusion of the study is that for the crude oil of high viscosity (~300 cP), hardly any effect was observed of increasing visco-elasticity on the oil recovery, even when both viscosity and flow rate were increased up to 300 cP and 3 ft/day, respectively. However, for the low viscosity crude (~9 cP), extra oil was recovered upon increasing the viscosity and/or flow rate of the polymer of high elasticity. No extra oil was recovered when using polymers of low elasticity even when using similar viscosity and flow rate, which indicates that it is an effect of elasticity and not of viscous stripping of residual oil saturation.
Thus, this paper confirms that polymers of high elasticity can reduce the residual oil to water. However, since this effect was only observed by either increasing the polymer viscosity or injection rate, the main challenge for field application is injectivity of the polymer at such high viscosity or rate, therefore before embarking on field application an injectivity test is required.
Improving Ultimate Recovery of Tight Sour Oil Field by Miscible Gas Injection
Authors: Cobanoglu M. , Jabri A. , Mahruqi F. , Sarmiento O. Quintero , Linthorst S. 
Published: June 2014

Abstract
The reservoir in South Oman – discovered in 1989 – is a 400m thick, tight, micro-porous silicilyte slab encased in salt at a depth of 4000m. The field contains the unique Athel silicilyte formation, some 4 km below the surface and is fully encased in salt as a result of which the reservoir is over-pressured at 800 bars. The Athel formation is sub-divided into 7 zones based on GR and Neutron/Density behavior. All zones are expected to be in hydrostatic communication despite the very low vertical permeability and the intensive layering of the silicilyte.
The crestal area has average matrix porosity of 22%. The permeability of the reservoir is extremely low (typically 1 – 100 μD) due to the fact that the rock mainly consists of micro-crystalline silica with abundant micro-solution seams and concretions/cemented beds and numerous sealing faults and fractures. The oil in this field is very light, low viscosity and volatile (48° API, Pb=260 bar, H2S=1.5%, CO2=2.5%). The application of massive hydraulic fracturing (2-4 frac/per well) combined with the favorable oil properties and under-saturated nature of the oil has made economic primary depletion development possible in this low permeability reservoir with reasonable initial oil rates (100-600 m3/day). Current oil recovery factor is 4.2% and expected to reach 10% through continued primary depletion. In 2007, an assessment of potential EOR applications aimed at improving the UR of the field concluded that MGI (miscible gas injection) via hydraulically fractured wells in the crestal area of the field is feasible, once field pressure has sufficiently declined. PVT experiments have demonstrated that miscibility pressure using its own produced hydrocarbon gas is close to the bubblepoint pressure of 260 bar. Subsequently a phased development was defined, depletion followed by MGI. Pilot injection into 2 patterns (Phase 3A) in the crest of the reservoir, will start end-2014 followed by a 2nd phase of crestal MGI (Phase 3B) by 2022. A final stage could be extension of MGI to the full field. With the application of full field MGI, the recovery factor could reach 40%.
The key risks for MGI are identified as early gas breakthrough, poor sweep, and limited injectivity. The pilot injection phase is designed to prove the MGI concept as well as to address these risks. Learnings and data acquisition from the pilot injection phase are essential for a decision on the future expansion of MGI.
This paper presents a methodology to evaluate this tight sour oil field development including EOR assessment, pilot injection monitoring plans and assessment of over 40 fracced wells.
Polymer Field Trial: Deployment of Intelligent Technologies for Horizontal Wells and Real-Time Approach for Surveillance
Authors: Awan K. , Al-Mjeni R. , Al-Abri K. , Rajhi S. , Al-Azri N. , Al-Bulushi N. , Ghulam J. , Sinha M. , Furaisi S. , Edwards J. 
Published: June 2014

Abstract
This paper describes key factors related to intelligent horizontal well completion systems and surveillance activities for a polymer field trial within a sandstone reservoir in the South of Oman. The existing field predominantly comprising of horizontal producer wells drilled and located at the crest of the reservoir to ensure optimum oil production rates via artificial lift techniques. Many wells have encountered early water breakthrough, resulting in large volumes of un-swept oil. Improved sweep efficiency, hence improved oil recovery is expected by polymer flooding using a horizontal well approach [1].
The polymer field trial location consists of: 4 horizontal producers each completed with wire wrap screens, blanks and external zonal isolation packers within the reservoir section for segmentation and isolation. Each producer has a downhole gauge for real-time pressure and temperature monitoring. Three horizontal smart injectors each consisting of 4 zones completed with 7 inch pre-drilled liners, blanks and external zonal isolation packers across the reservoir section for segmentation and zonal isolation. These injectors are internally completed with intelligent completion systems with remote access and control whereby each of the 4 zones consists of a mechanical retrievable packer for zonal isolation, on-off intelligent flow control valve with hydraulic multi-drop module system for conformance control, quartz pressure-temperature gauge, double ended pump down DTS system for real-time monitoring and internally lined GRE tubulars in order to prevent polymer degradation. Two horizontal observation wells each completed with GRE casings and predrilled liner joints for logging along with downhole gauges for real-time pressure-temperature monitoring. One vertical observation well completed with GRE casing and carbon steel casing below the oil water contact for surveillance purposes.
A detailed surveillance plan for the current producers, injectors and observation wells is of utmost importance for pre and post injection data gathering in order to successfully evaluate key subsurface risks and uncertainties associated with the polymer flood technique. The field trial has been designed and executed with an optimum approach to ensure continuous real-time surveillance. This is facilitated by remote access and control thereby minimizing well interventions for surveillance activities for the duration of the trial.
Reducing Key Uncertainties Prior to a Polymer Injection Trial in a Heavy Oil Reservoir in Oman
Authors: Al Abri K. , Al-Mjeni R. , K Al-Bulushi N. , Awan K. , Al-Azri Nasser , Al-Riyami O. , Al-Rajhi S. , Teeuwisse S. , Ghulam J. , Abu-Sheikha Issa , Douma Sippe 
Published: June 2014

Abstract
Polymer flooding was selected as the preferred enhanced recovery process for a high permeability (2-5 Darcy) heavy oil (250 – 500 cP) reservoir with a strong bottom aquifer in South Oman. Several key uncertainties were identified through simulation modelling which would have a crucial impact on the process efficiency. These uncertainties formed the basis of a field trial design, and a detailed surveillance programme aimed at reducing these key uncertainties.
The presence of a strong bottom aquifer in this field resulted in near original reservoir pressure, which could provide a challenge to injectivity. The close proximity of injectors to the oil water contact reduces the efficiency of the polymer flood through water fingering, and polymer loss to the aquifer. Additional uncertainties include: reservoir heterogeneity, Kv/Kh, permeability distribution, baffles, natural fractures, remaining oil saturation, injectivity, induced fracturing and inflow profile along the horizontal well (producers and injectors). Hence, extensive data gathering was carried out in order to reduce these uncertainties through updating the static and dynamic models and allowing for a better understanding of the field behavior prior to polymer injection.
This paper details a fully integrated evaluation of the gathered data through a multi-disciplinary team during the drilling of the trial wells. The data includes: open hole logs, borehole images, core analysis, fluid sampling, dielectric measurements, vertical interference testing, production logging and existing dynamic production data. Also, single well water and polymer injectivity test and extended leak-off test were carried out to understand the injectivity and fracture behavior. The wealth of well data coupled with geological and dynamic data reduced the overall reservoir properties and fluid distribution uncertainties. Furthermore, the data were crucial to design the optimum injection and data gathering requirements during the field trial. Finally, the paper provides an overview of the surveillance aspects of the field trial.
TPM's: A New Class of Viscoelastic Solutions for Enhanced Oil Recovery
Authors: Siggel L. , Radloff M. , Reimann S. , Hansch M. , Nowak M. , Ranft M. , Weiss H. , Schreiner E. , Brand F. 
Published: June 2014

Abstract
A new class of viscoelastic solutions -Triphenoxmethanes (TPM)-has been under development since early 2010 and remain a fruitful yet highly challenging research topic. The TPM's are viscoelastic at low concentrations (&lt;0.5%w/w) and show good stability in highly saline hard brines. They have been tested in hard brines up to 25% TDS with high divalent cation concentration and show increasing performance with increasing salinity. The current lead candidate "TPM", which is also being scaled up for a first field trial, displays good performance to 75°C. Adsorption/retention measurements show quite acceptable values for the harsh conditions under study. Porous media testing has shown that the TPM's have good injectivity properties and mobilize significantly more oil than brine alone. In addition, oil displacement experiments with cores at residual oil concentration (Sor) have clearly shown that TPM mobilizes residual oil (ca.7% OOIP) without significant reduction of the IFT and with less than 1 PV injected fluid.
The suitability for use in a particular reservoir is a complex interplay of the molecular structure of the TPM, temperature and brine salinity: lowering the salinity increases the application temperature. The interrelationship of the different factors is an on-going, high priority activity of the integrated R&D team. Here we report on the relevant aspects for application in harsh environments and give an outlook for field application.
Secondary and Tertiary Polymer Flooding on Highly Permeable Reservoir Cores: Experimental Results
Authors: Cottin C. , Bourgeois M. , Bursaux R. , Jimenez J. , Lassalle S. 
Published: June 2014

Abstract
This paper presents laboratory polymer core floods in secondary and tertiary mode carried out on highly permeable aged sandstone reservoir cores at reservoir temperature, with oil viscosities ranging from 7 (reservoir A) to 55 cP (reservoir B). Oil recovery is measured through three redundant techniques: mass balance, X-Ray saturation and miscible tracer test. Experimental results are interpreted to obtain polymer relative permeability curves by history matching oil production profiles, differential pressure and in-situ water saturation profiles at every step of the experiments.
The main results can be summarized in three points. Small scale heterogeneity and core quality have a large impact on the experimental results, making the comparison between different floods cumbersome, as well as between water flood and polymer flood. Polymer injection in this oil-wet high permeability reservoir changes the balance between capillary and viscous forces, leading to oil recovery in layers where capillary trapping is observed during water injection. Finally, there seems to be a difference in behavior between secondary and tertiary polymer floods, where the local residual saturation to polymer injection, as quantified by X-ray, is lower in secondary mode than in tertiary mode, while in tertiary mode both water and polymer injection have the same local residual oil saturation. Possible reasons as to why secondary polymer injection behaves differently than tertiary polymer injection are still being investigated.
Comprehensive Correlations to Calculate Viscosity of Partially Hydrolyzed Polyacrylamide
Authors: Gao Chang Hong 
Published: June 2014

Abstract
Polymer flooding is the most successful chemical enhanced oil recovery (EOR) method. This technique has achieved large-scale field applications at Daqing and Shengli oilfields in China. At Daqing oilfield, polymer flooding has improved oil recovery by 10%. At Shengli field, polymer flood has contributed to more than 22 million tons of oil since 1992.
The most common polymer for EOR projects is partially hydrolyzed polyacrylamide (HPAM). Since 1970s, continuous efforts have been spent on understanding the factors that influence the viscosity behavior of HPAM. It was discovered that shearing, heat, divalent ions and monovalent ions all have negative impacts on polymer viscosity. However it is still a challenge to predict the viscosity of HPAM under given reservoir conditions. The commonly used Carreau equation and Meter equation fail to consider the various factors that lead to loss of polymer viscosity.
In this paper, extensive laboratory tests were conducted to measure the viscosity of HPAM solution under the influences of shearing, high temperature, Calcium concentration and sodium concentration. Based on the test data, numerical correlations are proposed to predict the power law parameters. These formulas take into consideration the various factors that affect polymer viscosity. These correlations will help to improve the prediction of polymer viscosity under reservoir conditions, and will lead to more reliable design for polymer flooding projects.
Application of Streamline Simulation for Gas Displacement Processes
Authors: Nagib Mohamed , Burns Alan , Ingham Derek , Pourkashanian Mohamed , El-Banbi Ahmed H. 
Published: June 2014

Abstract
Streamline methods, in which fluid is transported along the streamlines instead of the finite difference grid, are widely used d in the oil industry. Larger time steps and higher spatial resolution can be achieved in streamline simulations. 3D flow problem is decoupled into a set of 1D problems solved along streamlines, which reduces the simulation time and suppresses the numerical dispersion. However, finite-difference reservoir simulation is widely used for solving large-scale multiphase displacement problems, streamline proved to be a faster tool for proper reservoir managment.
Proper assessment of miscible and near-miscible gas injection processes are usually carried out through conventional finite difference (FD) compositional simulation. Due to high-resolution simulation of the detailed geological model (Fine grid) is time consuming, coarse grid (Low resolution) models are normally used for testing the performance as a fast track process. Low-resolution compositional simulation is adversely affected by numerical dispersion and may fail to represent geological heterogeneities adequately. Streamline application will properly describe displacement and volumetric sweep in the fine grid model that capturing all reservoir heterogeneity.
Streamline computations assume incompressible fluids, and therefore they are not usually used for reservoir simulation of gas injection processes and for depletion studies below the bubble point. This paper presents the results of investigating the use of streamline techniques in gas displacement processes. A detailed comparison is given between the results of conventional FD simulation and the streamline approach. The comparison demonstrates that streamline simulation can be used in gas displacement processes under certain conditions. In such cases, the CPU time requirements and numerical dispersion can be reduced significantly while allowing the engineer to use a finely gridded model capturing the heterogeneity of the reservoir.
Experimental and Numerical Investigations into the Effect of Heterogeneity on Heavy Oil Recovery by VApour EXtraction (VAPEX)
Authors: Al-Hadhrami M. M. , Alkindi A. S. , Muggeridge A. H. 
Published: June 2014

Abstract
We used a combination of experimental, analytical and numerical approaches to examine the oil drainage rates obtained from VAPour EXtraction (VAPEX) process to recover heavy oil. In particular we investigated the influence of macroscopic scale heterogeneities through a series of experiments. These heterogeneities comprised layers, a quadrant model and two cases with discontinuous shale barriers above the injection well. All experiments were performed in well-characterized glass bead packs using glycerol and ethanol as analogues of heavy oil and solvent respectively. All the porous medium and fluid properties (including permeability, porosity, viscosity, density, diffusion and dispersion) were measured independently. The experimentally measured rates were compared to the estimates derived from the Butler-Mokrys analytical model. Numerical simulations were validated using the experimental observations from the homogenous and heterogeneous systems.
The findings confirmed the square root dependency of the oil rates on permeability (at least for the range of permeabilities used here) which is consistent with findings from previous studies. Despite that, the results indicated that the Butler-Mokrys derived expression under-predicts the physical oil rates, even when the effects of convective dispersion and end-point density difference (as suggested by other works) were factored in. Results from the heterogeneous models suggest that layering may not reduce VAPEX oil drainage rates significantly. They also showed that oil was not recovered from the lower permeability layers. For models with discontinuous shale barriers, the simulations tended to over-predict the oil rates compared with the experiments.
Overall the estimated rates from the simulations were more comparable to the physical rates than those estimated from the original Butler-Mokrys analytical derivation. Moreover the simulator was able to capture the pattern of solvent-oil distribution for both homogeneous models and heterogeneous models. This would suggest that the Butler-Mokrys model does not properly describe all the physical processes that are controlling the oil drainage rate even in homogeneous models.
Challenges in ‘Surface Facilities Implementation’ for a Full field Polymer Flood Project
Authors: Bhaumik Premashis , Mohanram Santosh 
Published: June 2014

Abstract
This paper discusses the key challenges in Surface Facilities implementation for a Full Scale Polymer Flood Project. The key challenges discussed include (a) availability of limited technology for high concentrated polymer dissolution, (b) transfer of high viscous Polymer Mother Solution with minimum viscosity loss, (c) water quality issues, (d) designing a feasible supply chain strategy for polymer logistics and (e) handling back-produced polymer associated with the well fluid.
Design of Horizontal Polymer Injectors Requiring Conformance and Sand Control
Authors: Bouts Marcel N. , Rijkeboer Marleen M. 
Published: June 2014

Abstract
For the redevelopment of a heavy oil field (160 cP), polymer flooding as an EOR technique has been studied. To minimize the number of wells and still achieve significant injection rates of 500-750 m3/d in the 30m thick reservoir, horizontal wells were designed. The completion included sand screens (WWS) with outflow control devices (OCD) to maximize injection conformance.
Key to the success of polymer injection at high rates is to ensure that the solution viscosity is maintained such that effective oil sweep takes place. Since EOR polymers are sensitive to mechanical shear (i.e. loss of viscosity when flown through restrictions), the completion design has been optimized by addressing the following:
Shear degradation tests in lab experiments using capillaries, sand screens, OCD nozzles and reservoir cores Assess the expected shear rates through the sand screens, the OCD nozzles and the near wellbore area, the latter is based on the Blake-Kozeny relationship and used in coreflow tests. A nodal analysis model using the non-Newtonian fluid model was constructed to analyse the conformance benefits and optimize the OCD nozzles.
The presented work indicates that horizontal polymer injectors requiring both conformance and sand control can be designed such that high injection rates can be achieved without jeopardizing the polymer viscosity.
Laboratory Study on Polymers for Chemical Flooding in Carbonate Reservoirs
Authors: Han Ming , Fuseni Alhasan , Zahrani Badr , Wang Jinxun 
Published: June 2014

Abstract
As part of the screening process for chemical EOR, several polymers have been screened as co-injectants in a surfactant-aided water flood scheme. Due to their higher viscosity, polymers improve sweep efficiency and reduce the permeability of rock matrix, therefore help to improve oil recovery. Aimed at a representative carbonate reservoir in the Middle East, a polymer screening study has been conducted with respect to polymer solubility and viscosity retention in high salinity brines, equivalent to our reservoir parameters. The polymers have to pass through a stringent screening process to meet the harsh conditions encountered in the reservoir: high temperature, high salinities and carbonate nature. Salinity effect was studied in a range of brines that included shallow formation water, produced water, and connate water. Among the polymers studied, six were found compatible and have been short-listed. Based on rheological measurements and flow curves, the concentrations of polymers have been determined to achieve the target viscosity under reservoir conditions. Long-term stability and adsorption tests were conducted to ensure the efficiency of the polymer exposed to reservoir conditions. Oil displacement tests with a selected polymer showed an increased oil recovery factor of 11% by polymer flooding and 18% by surfactant-polymer flooding. This study demonstrates the potential application of polymers under extremely harsh reservoir conditions and their promise to be good additives for chemical flooding.