Reichenbach-Klinke, Roland (BASF Construction Polymers GmbH) | Stavland, Arne (International Research Institute of Stavanger) | Langlotz, Bjorn (BASF Construction Chemicals GmbH) | Wenzke, Benjamin (BASF SE) | Brodt, Gregor (BASF SE)
New thickeners based on associative properties and their application in enhanced oil recovery are discussed. The new thickeners are anionic, water-soluble, hydrophobically modified copolymers.
The rheological properties as well as the flow properties in porous media have been evaluated. In bulk the polymer viscosity is shear thinning and the viscosity vs. shear rate profile is comparable with other synthetic EOR polymers. For most of the other tested parameters, the new thickeners differ from what is assumed as the standard properties for EOR polymers. The relative viscosity increases by increasing the temperature, especially at low shear rates. The core flood experiments revealed a significant mobility reduction in sandstone cores, both at ambient and elevated temperature. The mobility reduction demonstrated strongly shear thinning behavior. For standard EOR polymers the main contribution to the mobility reduction and improved mobility ratio is the polymer viscosity, while for the new thickeners the mobility reduction seems to be dominated by reversible polymer retention that is lowering the permeability. Post water injection resulted in low permeability reduction. However, the time to regain the permeability was significant.
Flood experiments with the associative polymer in Bentheim sandstone cores showed significantly increased oil production. The incremental oil recovery was interpreted by the capillary number which due to the high mobility reduction exceeded the critical capillary number. Because of the high mobility reduction a further increase in oil production would have been possible by only slight reduction of the oil-water interfacial tension by addition of small amounts of a surfactant. Moreover the new associative polymer seems to be more shear stable than other synthetic EOR polymers.
Humphry, Katherine Jane (Shell Global Solutions International) | van der Lee, Merit (Shell Global Solutions International) | Southwick, Jeff G. (Sarawak Shell) | Ineke, Erik M. (Shell Global Solutions International) | van Batenburg, Diederik W (Shell Global Solutions International)
Workflows to assess the technical and economic suitability of an enhanced oil recovery (EOR) technique for a particular field generally involve laboratory testing, such as core flooding experiments, and field-scale reservoir modelling. When building field scale models and interpreting laboratory experiments it is important to understand the flow properties of all phases present.
Alkali-surfactant-polymer flooding (ASP) is an EOR technique under consideration for a number of Malaysian oil fields. In ASP flooding, surface-active molecules decrease the interfacial tension between water and crude oil, increasing the capillary number, and recovering oil trapped in the reservoir pores. The ultra-low interfacial tensions needed for ASP flooding occur when the surface active molecules are equally soluble in the brine and oil phases. Under these conditions, in addition to the brine and oil phases, a third thermodynamically stable phase is formed. This third phase is known as a microemulsion. While the flow properties of crude oil and polymer-enriched brine are well understood, little has been done to characterize the microemulsion phase, particularly with respect to rheology in porous media.
Here, preliminary measurements of microemulsion rheology are presented. Large volumes of microemulsion, with and without polymer, are generated using model alkali-surfactant (AS) and alkali-surfactant-polymer (ASP) systems. These microemulsions are studied using conventional shear rheology. The viscosities measured using a conventional shear rheometer indicate microemulsion viscosities higher than either the AS(P) solution or decane from which they are comprised. Additionally, an in situ, or apparent, viscosity is recovered from core flooding experiments in Berea sandstone, where pressure drop across the core is recorded as a function of the flow rate of the microemulsion through the core. In situ viscosity measurements in Berea sandstone indicate apparent viscosities 1.5 to 6 times larger than those measured in a conventional shear rheometer. The implication of these results for ASP flooding is discussed.
Thakuria, Chandan (Petroleum Development Oman) | Al-Amri, Mohsin Saud (Petroleum Development Oman) | Al-Saqri, Kawthar Ahmed (Petroleum Development Oman) | Jaspers, Henri F (Petroleum Development Oman) | Al-Hashmi, Khalid Hamad (Petroleum Development Oman) | Zuhaimi, Khalid (Petroleum Development of Oman)
The first field scale Polymer flood project in the Middle East region is being implemented in an oil field of Sultanate of Oman from early 2010. The oil field discussed here containing viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding.
This field scales Polymer flood project comprising 27 patterns as Phase-1 covers about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in all these 27 injectors. Further extension in phases to full field polymer flooding is under evaluation.
Till now this Polymer flood project has successfully completed 3 years of good performance contributing to significant oil gain. This paper describes briefly about the principles involved in polymer flooding, planning of this polymer flood project, field implementation and field examples of polymer response. In addition, a few practical aspects of managing key issues in polymer flooding like- fracture growth in injectors, shear degradation of polymer solution, pattern conformance and back produced polymer has been covered in this paper.
Factors confronting the application of surfactant flood in high temperature, high salinity carbonate reservoirs include: high concentration of divalent ions in the formation brine, the stability of the surfactant in high thermal environment, surfactant adsorption on carbonate rock fabrics and the effect of high salinity and brine mineral composition on the multiphase system, typically encountered in carbonate reservoirs. For preliminary screening purposes, thermal stability, salinity tolerance and emulsification characteristics are given importance, while the capacity to alter the wettability of the reservoir rock towards a water-wet system is desired.
Several surfactants were screened based on their abilities to address issues of high thermal environment, high salinity effects and capacity to create a water-wet environment. A series of akyl-polyglucoside (APG) surfactants were studied which are established as eco-friendly, renewable, nontoxic and bio-degradable surfactant and one of them found to be suitable for the target carbonate reservoir. An unique approach adopted during the screening process for thermal stability was the analysis of the UV-visible light absorption profile of the surfactants after subjecting them to reservoir condition for specific periods. The APG showed salinity tolerance up to 263,000 ppm at 220 oF. During phase study divalent ions are seen to have considerable impact on the nature of microemulsion (middle phase). Incremental recovery between 19-15% was observed for surfactant flood after secondary waterflood and spontaneous imbibition of aqueous phase was enhanced in the presence of surfactant solution. The recovery was correlated with microemulsion phase behavior and wettability alteration.
Ma, Kun (Rice University) | Farajzadeh, Rouhi (Shell Global Solutions International) | Lopez-Salinas, Jose L. (Rice University) | Miller, Clarence A. (Rice University) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George J. (Rice University)
In the absence of oil in the porous medium, the STARSTM foam model has three parameters to describe the foam quality dependence, , , and . Even for a specified value of , two pairs of values of and can sometimes match experimentally measured and . This non-uniqueness can be broken by limiting the solution to the one for which < . Additionally, a three-parameter search is developed to simultaneously estimate the parameters , , and that fit the transition foam quality and apparent viscosity. However, a better strategy is to conduct and match a transient experiment in which 100% gas displaces surfactant solution at 100% water saturation. This transient foam quality scans the entire range of fractional flow and the values of the foam parameters that best match the experiment can be uniquely determined. Finally, a three-parameter fit using all experimental data of apparent viscosity versus foam quality is developed.
The numerical artifact of pressure oscillations in simulating this transient foam process is investigated by comparing finite difference algorithm with method of characteristics. Sensitivity analysis shows that the estimated foam parameters are very dependent on the parameters for the water and gas relative permeability. In particular, the water relative permeability exponent and connate water saturation are important.
The development of chemical enhanced oil recovery projects throughout the world is on a fast pace, led by a will to increase the final recovery of mature and newly developed hydrocarbon reservoirs The validation of the process is usually achieved by implementing an injection pilot; the goal is to understand, secure, and optimize the technology and to assess its efficiency on increasing final oil recovery for carefully determined capital and operational expenditures.
One of the key factors for a successful polymer flood is the polymer solution viscosity that must remain on target during the transport from its initial preparation, to the well head and down to the reservoir. Thus, a reliable method is required to measure and monitor the polymer solution viscosity on different points along the dissolution, dilution, mixing, and injection lines. This method must take into account the polymer solution characteristics among which the non-Newtonian behavior and sensitivity to mechanical and chemical degradations.
This paper presents recent developments of a specific in-line viscometer, which can measure the viscosity at low shear-rate, as per real reservoir conditions, with pressures ranging up to 250 barg. The equipment consists in a low flow, non-shearing pump, which circulates the solution through a given tube (length and diameter) where the pressure drop is measured and allows low-shear viscosity to be extrapolated. Calibration methods and first results are presented in this paper to illustrate the accuracy of the technology and potential installation benefits for chemical enhanced oil recovery operations. The viscometer is made of highly resistant material and can be implemented in all hazardous areas in remote mode without manual operations, no waste and very little maintenance.
This new device has been designed to solve the common issues encountered with the vast majority of commercial equipment that is not compatible with currently injected polyacrylamide solutions. It will also allow operators to gather reliable data compared to manual sampling methods that, in addition to requiring manpower, are not easy to conduct without degrading the polymer solutions.
This paper discusses a structured combination of procedures used to investigate polymers for EOR application with the focus on performance, compatibility with production chemicals and phase behaviour. This approach allows for early identification of risks and points to further work necessary for mitigation before field implementation. The case studied here was a system with total dissolved solids (TDS) of 80000 mg/l and temperature requirements of 40 to 70 oC. Effective screening of polymers has benefited from dissolution/viscosity, thermal stability and filtration tests. At lower temperatures (40 oC), polymers were shown to be fit-for-purpose for the conditions evaluated. All polymers showed loss of viscosity with some leading to complete viscosity loss at increased temperatures. This is the result of hydrolysis and interaction with the divalent cations present in the make-up synthetic brine. In-situ viscosity allowed for identification of phase behaviour effects which could affect injectivity (difference in apparent and rheometer viscosity). For the best performing polymer the presence of corrosion and scale inhibitors did not affect viscosity. No detrimental effects on corrosion inhibition and water in oil emulsions were observed. Increases in oil in water with potential fouling/deposition was identified for future study.
Polymer flooding is a well established tertiary EOR technique to improve mobility control of a waterflood. Currently partially hydrolyzed polyacrylamide (HPAM) is the industry workhorse in polymer EOR in reservoirs with low salinity and temperature. Biopolymers including hydroxyethylcellulose (HEC) and Xanthan are soluble and excellent viscosifiers in high salinity conditions. This paper will provide a literature review on the use of biopolymers for EOR and focus specifically on the benefits of HEC as a mobility control polymer.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration & Development, CNPC) | Weng, Rui (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration & Development, CNPC) | Luo, Yousong (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration & Development, CNPC)
For mature oil fields, foam flooding is an attractive chemical EOR technique and many pilot tests have been carried out in China. The performance of foam flooding pilot tests and its affect factors on oil recovery was discussed in this paper. The development trend and key technologies of foam flooding technique are pointed out.
Eighteen foam flooding pilot tests have been carried out in China from 1994 to 2010. Good performance have achieved in sixteen pilot tests. Through effects analysis of the pilot tests, three main aspects are concluded for affecting the performance of foam flooding tests. First, the characteristics of target reservoirs influence effects of foam flooding tests. The performance of foam flooding in higher oil viscous reservoirs is better than that in light oil reservoirs. The reservoir temperature and formation water salinity also influences the effects of foam flooding. Secondly, the chemical formula of foam solution and the size of slug influence the performance of foam flooding. The stability of foam formula influences the effects of foam flooding greatly. With the same amount of surfactant solution, the effect of high concentration small-sized slug is better than that in low concentration large-sized slug. Last, the injection method and gas liquid ratio can directly influence the foam performance in the reservoir, gas and liquid mixing injecting model is better than surfactant solution-alternation-gas (SAG) injection, and reasonable gas liquid ratio is important for guarantee good effects of foam flood.
At present, the trend of foam flooding in China is from nitrogen foam flooding and natural gas foam flooding to air foam flooding. The key technologies of foam flooding are the development of high stable foam formula with oil tolerance, salt and temperature resistance, good injection method and reasonable injection parameter etc.
Koroteev, Dmitry Anatolyevich (Schlumberger) | Dinariev, Oleg (Schlumberger) | Evseev, Nikolay (Schlumberger) | Klemin, Denis Vladimirovich (Schlumberger R&D Inc.) | Safonov, Sergey (Schlumberger) | Gurpinar, Omer M. (Schlumberger) | Berg, Steffen (Shell Global Solutions International BV) | vanKruijsdijk, Cor (Shell) | Myers, Michael (Shell) | Hathon, Lori Andrea (Shell International E&P Co.) | de Jong, Hilko (Shell Oil Co.) | Armstrong, Ryan (Shell)
Fast and reliable EOR process selection is a critical step in any EOR project. The digital rock (DR) approach jointly developed by Shell and SLB is aimed to be the smallest scale yet advanced EOR Pilot technology. In this document, we describe the application of DR technology for screening of different EOR mechanisms at pore-scale focused to enhance recovery from a particular reservoir formation. For EOR applications DR brings unique capabilities as it can fully describe different multiphase flow properties at different regimes.
The vital part of the proposed approach is the high-efficient pore-scale simulation technology called Direct Hydrodynamics (DHD) Simulator. DHD is based on a density functional approach applied for hydrodynamics of complex systems. Currently, DHD is benchmarked against multiple analytical solutions and experimental tests and optimized for high performance (HPC) computing. It can handle many physical phenomena: multiphase compositional flows with phase transitions, different types of fluid-rock and fluid-fluid interactions with different types of fluid rheology. As an input data DHD uses 3D pore texture and composition of rocks with distributed micro-scale wetting properties and pore fluid model (PVT, rheology, diffusion coefficients, and adsorption model). In a particular case, the pore geometry comes from 3D X-ray microtomographic images of a rock sample. The fluid model is created from lab data on fluid characterization. The output contains the distribution of components, velocity and pressure fields at different stages of displacement process. Several case studies are demonstrated in this work and include comparative analysis of effectiveness of applications of different chemical EOR agents performed on digitized core samples.