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Collaborating Authors
Energy
Upscaling Laboratory Result of Surfactant-Assisted Spontaneous Imbibition to the Field Scale through Scaling Group Analysis, Numerical Simulation, and Discrete Fracture Network Model
Zhang, Fan (Texas A&M University) | Saputra, I. W. (Texas A&M University) | Niu, Geng (Texas A&M University) | Adel, Imad A. (Texas A&M University) | Xu, Liang (Halliburton) | Schechter, David S. (Texas A&M University)
Abstract Field experience along with laboratory evidence of spontaneous imbibition via the addition of surfactants into the completion fluid is widely believed to improve the IP and ultimate oil recovery from unconventional liquid reservoirs (ULR). During fracture treatment with surface active additives, surfactant molecules interact with the rock surface to enhance oil recovery through wettability alteration combined with interfacial tension (IFT) reduction. The change in capillary force as the wettability is altered by the surfactant leads to oil being expelled as water imbibes into the pore space. Several laboratory studies have been conducted to observe the effectiveness of surfactants on various shale plays during the spontaneous imbibition process, but there is an insufficient understanding of the physical mechanisms that allow scaling the lab results to field dimensions. In this manuscript, we review and evaluate dimensionless, analytical scaling groups to correlate laboratory spontaneous imbibition data in order to predict oil recovery at the field scale in ULR. In addition, capillary pressure curves are generated from imbibition rate theory originally developed by Mattax and Kyte (1962). The original scaling analysis was intended for understanding the rate of matrix-fracture transfer for a rising water level in a fracture-matrix system with variable matrix block sizes. Although contact angle and interfacial tension (IFT) are natural terms in scaling theory, virtually no work has been performed investigating these two properties. To that end, we present scaling analysis combined with numerical simulation to derive relative permeability curves, which will be imported into a discrete fracture network (DFN) model. We can then compare analytical scaling methods with conventional dual porosity concepts and then progressed to more sophisticated Discrete Fracture Network concepts. The ultimate goal is to develop more accurate predictive methods of the field-scale impact due to the addition of surfactants in the completion fluid. Correlated experimental workflows were developed to achieve the aforementioned objectives including contact angle (CA) and IFT at reservoir temperature. In addition, oil recovery of spontaneous imbibition experiments was recorded with time to evaluate the performance of different surfactants. Capillary pressure-based scaling is developed by modifying previously available scaling models based on available surfactant-related properties measured in the laboratory. To ensure representability of the scaling method; contact angle, interfacial tension, and ultimately spontaneous imbibition experiments were performed on field-retrieved samples and used as a base for developing a new scaling analysis by considering dimensionless recovery and time. Based on the capillary pressure curves obtained from the scaling model, relative permeability is approximated through a history matching procedure on core-scale numerical models. CT-Scan technology is used to build the numerical core plug model in order to preserve the heterogeneity of the unconventional core plugs and visualize the process of water imbibition in the core plugs. Time-lapse saturation changes are recorded using the CT scanner to visualize penetration of the aqueous phase into oil-saturated core samples. The capillary and relative permeability curves can then be used on DFN realizations to test cases with or without surfactant. The results of spontaneous imbibition showed that surfactant solutions had a higher oil recovery due to wettability alteration combined with IFT reduction. Our upscaling results indicate that all three methods can be used to scale laboratory results to the field. When compared to a well without surfactant additives, the optimum 3-year cumulative oil production of well that is treated with surfactant can increase by more than 20%.
- Geology > Mineral (0.46)
- Geology > Petroleum Play Type > Unconventional Play (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Information Technology > Mathematics of Computing (0.71)
- Information Technology > Communications > Networks (0.40)
Unstable Waterflood Performance Diagnostic Methods
Tillero, Edwin (Halliburton) | Mogollón, Jose Luis (Halliburton) | Gomez, Delfín (Halliburton) | Zambrano, Hector (Halliburton)
Abstract This paper discusses a review and adaptation of some classic waterflood performance analytical methods, such as X-plot, comprehensive Y-plot (cY-plot), and WOR vs cumulative oil (Np) for the case of unstable immiscible displacement (viscous-oil fingering effect). These methods were reviewed based on fractional flow analysis (FFA) for unstable immiscible waterflood. These classic techniques account for the solution of the one-dimension frontal advance Buckley-Leverett theory (1942), assuming stable flow. In addition, the traditional semilog linear relationship between oil-water relative permeability ratio and water saturationis assumed (constant parameters A and B). Those assumptions tend toover predict ultimate oil recovery for the case of viscous-oil waterfloods because flow functions do not capture the viscous fingering effect. This work proposes to redefine aforementioned classic waterflood performance analytical methods with novel oil and water relative permeability expressions derived from the effective-fingering model(EFM) presented by Luo et al. (2016), which accounts for viscous fingering effects. In addition, an accurate exponential expression of kro/krw ratio as function of water saturation and an exact solution for a water saturation-dependent parameter B (named Bj) are proposed. New approaches of classic analytical methods were derived, and both laboratory and field cases were tested at the light of new equations. Adaptation of classic equations (stable) to solutions that account for unstable flow results in more reliable diagnostic-plot techniques for the case of viscous-oil, allowing to correct predictions of oil and water production in the case of heavy-oil waterflooding Additionally, new equations resulted in unified solutions that can be applied for both stable and unstable waterflood and help to improve reliability when estimating ultimate oil recovery, volumetric sweep efficiency, and various reservoir parameters. In the presence of viscous fingering, the water breakthrough and oil recovery from new X, cY, and WOR functions are viscous-finger number dependent (Nvf). The bigger the Nvf the lower the oil recovery, the earlier the water breakthrough, and the narrower the water saturation ranges. In its entirety, these novel waterflood performance analytical methods incorporate viscous fingering features in the traditional flow functions, encouraging the ability to predict ultimate oil recovery for both unstable and stable waterflooding cases and for chemical flooding (i.e., polymer with future adaptation) in heavy-oil reservoirs and facilitating the optimization of heavy-oil enhanced oil recovery (EOR) projects. These results might provide a basis to adapt other classic waterflood performance analytical methods.
Estimation of Capillary Pressure and Relative Permeability from Downhole Advanced Wireline Measurements for Waterflooding Design
Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company) | Azari, Mehdi (Halliburton) | Hadibeik, Hamid (Halliburton) | Kalawina, Mahmoud (Halliburton) | Hashmi, Gibran (Halliburton) | Hamza, Farrukh (Halliburton) | Ramakrishna, Sandeep (Halliburton)
Abstract Reservoir relative permeability and capillary pressure, as a function of saturation, is important for assessing reservoir hydrocarbon recovery, selecting the well completion method, and determining the production strategy because they are fundamental inputs to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability and capillary pressure curves at reservoir conditions is also an important task for successful planning of waterflooding and enhanced oil recovery. The relative permeability and capillary pressure data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability and capillary pressure curves with downhole pressure-transient analysis (PTA) of mini-drillstem tests (miniDSTs) and well log-derived saturations. The new approach was based on performing miniDSTs in the free water, oil, and oil-water transition zones. Analyses of the miniDST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining these downhole measurements provided the relative permeability and capillary pressure curves.
- Europe (1.00)
- North America > United States > Texas (0.95)
- North America > United States > California (0.68)
- Asia > Middle East > Kuwait > Ahmadi Governorate (0.29)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (17 more...)
Snorre In-Depth Water Diversion - New Operational Concept for Large Scale Chemical Injection from a Shuttle Tanker
Skrettingland, K.. (Statoil ASA) | Ulland, E. N. (Statoil ASA) | Ravndal, O.. (Statoil ASA) | Tangen, M.. (Statoil ASA) | Kristoffersen, J. B. (Statoil ASA) | Stenerud, V. R. (Statoil ASA) | Dalen, V.. (Statoil ASA) | Standnes, D. C. (Statoil ASA) | Fevang, Ø.. (Statoil ASA) | Mevik, K. M. (Knutsen Subsea Solutions) | McIntosh, N.. (Knutsen Subsea Solutions) | Mebratu, A.. (Halliburton) | Melien, I.. (Halliburton) | Stavland, A.. (Intl Research Inst of Stavanger)
Abstract Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper. After the injection of approximately 400,000 Sm (113,000 Sm preflush, followed by 240,000 Sm of sodium silicate gelant and 49,000 Sm of postflush fluid) at injection rates up to 4,000 Sm/d, the injection from the vessel was stopped and the well was put on regular seawater injection. Following more than two years of regular production, transient pressure measurements, tracer testing and water cut data are presented from the ongoing comprehensive data acquisition program. These results demonstrate clearly the achieved in-depth flow diversion through a delayed breakthrough of injected tracers and lower water cut in the relevant production well.
- North America > United States (1.00)
- Europe > Norway > North Sea > Northern North Sea (0.48)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (27 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
Abstract One of the primary problems for mature oilfield operators is the production of undesired fluids, such as water or gas. Cantarell is a mature field wherein one of the greatest challenges is managing produced water. Mature oil fields experience severe water production, which can be challenging in naturally fractured carbonate reservoirs that produce through a thick layer of oil. A new technology combining two conformance systems was used to alleviate water production in a well in this field, returning production to optimal levels. The study well (Well A) was shut in because of high water cut (90 to 100%), and post-analysis of this problem showed water coning from fractures in the Lower Cretaceous formation. The well has a unique interval, and perforating a deeper interval was not possible because the water-oil contact (WOC) was close. The solution selected for this case was a combination of two conformance technologies for water control that permit sealing high permeability channels and fractures and, more importantly, help provide selective water control—one is a swelling polymer designed to shut off water channels, fractures, or highly vugular zones, and the other is hydrocarbon-based slurry cement that reacts on contact with water. The result was the recovery of a producer well with 1,197 BOPD with 14% water cut. After 19 months, production averaged 1,300 BOPD for that month with 40 to 66% water cut. Correctly diagnosing the problem and combining conformance technologies can help operators resume production of wells considered lost because of undesired fluids production. Therefore, this technology could be used to benefit reservoir optimization and production.
- North America > United States (1.00)
- North America > Mexico (1.00)
- Europe (0.69)
- Geology > Petroleum Play Type > Unconventional Play (0.48)
- Geology > Rock Type (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)