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Collaborating Authors
Stoll, Martin
Potential of Alkaline Surfactant Polymer (ASP) Flooding in a Medium-Light Oil Reservoir with Strong Bottom Aquifer
Al-Sulaimani, Hanaa (Petroleum Development Oman) | Stoll, Martin (Shell U.K.) | Wunnik, John Van (Petroleum Development Oman) | Faber, Rien (Shell Global Solutions International B. V.) | Arkesteijn, Fred (Shell Global Solutions International B. V.)
Abstract A central Oman oil field was evaluated for the potential of an ASP flooding development. The field is a sandstone reservoir containing medium to light oil of 33° API with a viscosity of 9cP. Till today, the field is under natural depletion with, lately, pressure supported by water injection into the aquifer at the NW and SW flanks. The recovery factor is already high and currently the field water cut is at 97%. Recently, an EOR screening study was conducted on PDO's fields and the subject field was found to be one of the potential candidates for ASP flooding. Several lab experiments were conducted on reservoir rock and fluid samples to assess the potential of an ASP application. The ASP formulation was tested on two wells in this field through the Single Well Chemical Tracer (SWCT) test technique where the residual oil reduced from 20% to 4% for one well and from 15% to 8% for the other. Different development scenarios were evaluated: a scenario that makes use of the strong bottom aquifer in combination with horizontal injectors near the OWC was found to be a technically viable development option. The liquid rate forecasts were subsequently used in the project economics showing that the company's screening criteria were met. The full field development versus phased development approaches were also evaluated where the latter was found to be favorable as it allows for early starting and proper de-risking for following phases. The subsurface feasibility study for this reservoir revealed that there is an opportunity of increasing the Recovery Factor of this field by more than 10%. This paper will describe in detail the study and the overall de-risking strategy with its various phases namely; lab experiments, single well tests, full field evaluation and showing of commercial attractiveness and finally the optimized implementation through phasing.
- North America > United States (0.47)
- Asia > Middle East > Oman (0.35)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.40)
Alkali-Surfactant-Polymer Flooding Pilot Test in Southern Oman
Finol, Jose (Petroleum Development Oman) | Al-Harthy, Said (Petroleum Development Oman) | Jaspers, Henri (Petroleum Development Oman) | Batrani, Ahlam (Petroleum Development Oman) | Al-Hadhrami, Hatim (Petroleum Development Oman) | van Wunnik, John (Petroleum Development Oman) | Stoll, Martin (Shell Technology Oman) | Faber, Rien (Shell Global Solutions International BV) | De Kruijf, Alexander (Shell Global Solutions International BV)
Abstract Petroleum Development Oman is advancing a pattern flood pilot in a major sandstone field in Southern Oman that uses a chemical EOR flooding process to recover additional reserves. An EOR screening study showed that Alkali-Surfactant-Polymer is a viable technology for this viscous oil reservoir (90 cP). A successful ASP pilot test will pave the way to potentially implement the process in other sandstone fields in the Southern Oman Basin. The ASP pilot test is a unique project in which two anionic surfactants have been specifically designed for the actual reservoir conditions. Laboratory tests indicated significant and comparable recovery from both outcrop and field cores. A high molecular weight polyacrylamide polymer designed to provide a favorable mobility ratio has also been tested at in-situ conditions. The primary objectives of the ASP pilot test are to validate laboratory results, demonstrate long term injectivity of the viscous ASP solution, reduce the range of technical and economic uncertainties associated with recovery efficiency and field operations and obtain data to calibrate dynamic models for accurate full-field predictions and economics. The field pilot consists of a 1.4 acres inverted 5-spot pattern that includes 4 corner vertical oil producers, 1 central injector and 2 observation wells. The 53m producer-to-injector distance enables early ASP flood response (4 to 5 months) and ensures completion of the field trial within one year of injection. Injection/production facilities will be skid-mounted and located in the vicinity of the pilot wells. Pilot commissioning and first ASP injection is anticipated to start in mid 2014. This paper presents both subsurface and facility aspects of the ASP pilot test design, including four successful single-well ASP/SWCT field tests, one ASP flood MicroPilot, and the experimental results of oil-water-ASP emulsion separation experiments.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > Middle East > Oman > South Oman > South Oman Salt Basin > Al Khlata Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Nahr Umr Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Mahwi Formation (0.96)
- Asia > Middle East > Oman > South Oman > South Oman Salt Basin > Gharif Formation (0.94)
Plans for Chemical Enhanced Oil Recovery in a North Oman Carbonate Field
Soek, Harry (1 Petroleum Development Oman, Muscat, Sultanate of Oman,) | Jaboob, Musallam (1 Petroleum Development Oman, Muscat, Sultanate of Oman,) | Singh, Maniesh (1 Petroleum Development Oman, Muscat, Sultanate of Oman,) | Jabri, Ahmed (1 Petroleum Development Oman, Muscat, Sultanate of Oman,) | Stoll, Martin (2 Shell Technology Oman, Muscat, Sultanate of Oman &) | Faber, Rien (3 Shell International E&P, Rijswijk, The Netherlands) | Al Harthy, Khalfan (1 Petroleum Development Oman, Muscat, Sultanate of Oman,) | Al Mjeni, Rifaat (2 Shell Technology Oman, Muscat, Sultanate of Oman &) | Wunnik, John van (1 Petroleum Development Oman, Muscat, Sultanate of Oman,)
Abstract Most of PDO’s carbonate fields in North Oman have been producing for many years, initially on depletion in the early days but were quickly put on water injection to maintain reservoir pressure and safeguard long term ultimate recovery. As these fields mature into early middle age, EOR options have been under review to further increase recovery. Given the reservoir properties and the prevailing fluid & gas conditions for these carbonate fields, thermal technologies are not considered an optimal choice. Gas floods would potentially feature but were screened out due to the overall balance between gas requirements, cost and potential reward. Chemical floods with potentially attractive high recoveries were selected for further assessment. The goal is to demonstrate that chemical technology can produce economic incremental oil from a waterflooded carbonate reservoir containing a low-viscous light oil. The reservoir selected has undergone a successful waterflood implementation with good control on historical voidage and production allocation. The potential follow up chemical flood is then planned to be introduced in a phased manner. This starts with phase behaviour and core flow experiments in the lab to find a suitable chemical formulation to optimally mobilize waterflood residual oil. This is then followed by field trials such as a Single Well Chemical Field Test to back up lab experiments, extensive logging, a MicroPilot test and a planned potential multi-well pilot. Full field implementation is then dependant on the results of the earlier project phases and will have to balance against the perceived rewards, risk and cost. The results to date, learning's and key findings along with the selection strategy and challenges will be discussed in this paper. This study and field work will provide a foundation upon which the future potential for chemical flooding in North Oman carbonate fields can be evaluated and implemented.
- Asia > Indonesia > East Kalimantan > Kutei Basin > Mahakam Block > Handil Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- (2 more...)
Toward Field-Scale Wettability Modification—The Limitations of Diffusive Transport
Stoll, Martin (Shell E&P International Ltd) | Hofman, Jan (Shell Intl. E&P BV) | Ligthelm, Dick J. (Shell Intl. E&P BV) | Faber, Marinus J. (Shell Intl. E&P BV) | van den Hoek, Paul (Shell International Exploration and Production)
Summary Densely-fractured oil-wet carbonate fields pose a true challenge for oil recovery that traditional primary and secondary processes fail to meet. The difficulty arises from the combination of two unfavorable characteristics: First, the dense fracturing frustrates an efficient waterflood; second, because of the oil-wetness, the water pressure exceeds the oil pressure inside the matrix blocks, thus inhibiting spontaneous imbibition of water. In the past decade, using a new class of surfactants, enhanced oil recovery (EOR) researchers have studied the options to chemically revert the wettability of carbonate rock without drastically decreasing the oil-water interfacial tension. These chemicals, termed "wettability modifiers" (WMs), effectively reverse the sign of capillary pressure at the prevalent saturation. With the oil pressure exceeding the water pressure, the capillary pressure becomes the driving force for oil expulsion from the matrix and into the fracture system. Previous publications on chemical wettability modification focused on the performance of different chemical wettability modifiers for a chosen rock/oil/brine system. In some cases, they demonstrated an almost full oil recovery from core plugs. Little attention, however, has been given to the mechanism underlying the transport of the chemical into the matrix block and to the proper scaling of laboratory results to reservoir size. The present study aims to demonstrate that imbibition after wettability modification is diffusion-limited. To this end, the recovery profiles for spontaneous capillary imbibition, as well as for imbibition after wettability modification, are calculated. The results are then used to compare with the data of Amott cell imbibition experiments. It is confirmed that in both cases, the cumulative recovery is initially proportional to the square root of time. Imbibition after wettability modification, however, takes approximately 1,000 times longer than spontaneous capillary imbibition into a water-wet medium. The slow recovery observed in the case of imbibition after wettability modification is in excellent agreement with the assumption that, in the absence of significant spontaneous imbibition, the WM, to unfold its action, must first diffuse into the porous medium. In any diffusion process, the time scale is linked to the square of the length scale of the medium. Therefore, it would take up to 1,000 times longer (an equivalent of 200 years) before the same recovery is obtained from a meter-scale matrix block as is obtained from a centimeter-scale plug in a laboratory in 100 days. Consequently, unless a significantly faster transport mechanism for the wettability modifier is identified, or unless viscous forces or buoyancy enable forced imbibition, the chemical wettability modification of fractured oil-wet carbonate rock does not provide an economically interesting opportunity. Introduction Rock fractures provide comparatively highly permeable flow paths through oil reservoirs. In a densely fractured reservoir, the permeability contrast between the fracture network and the oil-bearing matrix can be significant. In that case, the viscous pressure differential across individual matrix blocks can be too small to release oil from the blocks under waterflood, thus leading to a poor recovery. Depending on the wetting state of the matrix and its initial water saturation, Swi, capillary action can cause imbibition of water up to a "spontaneous" equilibrium saturation, commonly denoted as Sspw. At this saturation, however, the capillary pressure inside the matrix block coincides with that in the fracture, and the recovery ceases. Experience has shown that carbonate fields often range from intermediate-wet to preferentially oil-wet (Treiber et al. 1972; Chilingar and Yen 1983), which is synonymous with Sspw being close or equal to Swi ; thus, they exhibit very limited recovery during primary and secondary production. Recently, a new EOR technique, designed specifically to tackle the challenges outlined previously, has been suggested by Austad and coworkers (Austad and Milter 1997; Standnes and Austad 2000a, b). In their pioneering work, these authors show that certain chemicals, when dissolved in the surrounding brine, can initiate water imbibition into oil-saturated core plugs and, hence, lead to the recovery of oil. One possible mechanism that explains these observations is the solubilization of adsorbed hydrocarbon components from the pore surface—as demonstrated by an atomic force microscopy study by Kumar et al. (2005), this exposes the intrinsically hydrophilic matrix. Another possibility is the formation of an additional chemical layer covering the adsorbed hydrophobic material. In either case, the pore surface becomes more hydrophilic, and the wettability of the matrix is thus modified. In a capillary rise experiment into parallel plates, Kumar et al. also observed different time scales for different types of wettability-modifying chemicals (2005). Using the cationic wettability modifier dodecyl trimethyl ammonium bromide (DTAB, also known as C12TAB), Standnes and Austad deduced that wettability modification was achieved through the comparatively slow process of partitioning the chemical into the oil phase, followed by desorption and solubilization of anionic hydrocarbon components (2000a, b). Shen et al. (2006) and Rao et al. (2006) measured the effect of surfactants on the relative water/oil permeabilities at different interfacial tensions. Wu et al. (2006) studied the properties and ranked the efficiency of chemical model compounds, based on their chemical structure, to modify the wettability and enhance recoveries. Several groups have taken initiative to model wettability modification in numerical simulators (Adibhatla et al. 2005; Delshad et al. 2006). So far, no significant attention has been given to time dependence and to the subsequent upscaling of the laboratory results to matrix block scale. This subject will be addressed in the present work. The structure of the article is as follows: In the Theory section, the basic results for countercurrent capillary imbibition will be briefly reviewed and compared to Fick's law of molecular diffusion. The oil recovery as a function of time for both capillary imbibition and imbibition after wettability modification will be predicted. The experimental approach to imbibition at different wetting situations will be described in the section Materials and Preparation. The recovery results will then be analyzed using the previously derived equations. Finally, tentative conclusions for the upscaling will be drawn.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.44)
- Geology > Geological Subdiscipline (0.34)
Field-scale Wettability Modification - The Limitations of Diffusive Surfactant Transport
Stoll, Martin (Shell E&P International Ltd) | Hofman, Jan (Shell Intl. E&P BV) | Ligthelm, Dick Jacob (Shell Intl. E&P BV) | Faber, Marinus J. (Shell Intl. E&P BV) | van den Hoek, Paul (Shell International Exploration and Production Inc.)
Abstract Densely fractured oil-wet carbonate fields pose a true challenge for oil recovery, which traditional primary and secondary processes fail to meet. The difficulty arises from the combination of two unfavourable characteristics: the dense fracturing frustrates an efficient water-flood; the negative capillary pressure retains the oil inside the matrix blocks because oil is the wetting phase. In the past decade, EOR researchers have studied options to chemically revert the wettability of carbonate rock while not decreasing the oil-water interfacial tension drastically, using a new class of surfactants. These chemicals termed "wettability modifiers" (WM) effectively reverse the sign of the capillary pressure function such that the capillary pressure becomes the driving force for oil expulsion from the matrix into the fracture system. Previous publications on chemical wettability modification focused on the different chemical properties of the rock/oil/WM-brine system and demonstrated up to almost full oil recovery from core plugs. Little attention, however, has been paid to the mechanism underlying the transport of the chemical into the matrix block and to proper scaling of laboratory results to reservoir size. The present study aims to demonstrate that imbibition after wettability modification is diffusion-limited. To this end the recovery profiles for spontaneous capillary imbibition as well as for imbibition after wettability modification are calculated. The results are then used to match the data of Amott cell imbibition experiments. It is confirmed that in either case the cumulative recovery is initially proportional to the square root of time. Imbibition after wettability modification, however, takes about 1000 times longer than spontaneous capillary imbibition into a water-wet medium. The slow recovery observed for the case of imbibition after wettability modification is in excellent agreement with the assumption that, in the absence of significant spontaneous imbibition, the wettability modifier must first diffuse into the porous medium to unfold its action. In any diffusion process the time scale is linked to the square of the length scale of the medium. Therefore, it would take up to 1000 times longer, equivalent to 200 years, before the same recovery is obtained from a metre-scale matrix block as is obtained from a centimetre scale plug in the laboratory in 100 days. Consequently, unless a significantly faster transport mechanism for the wettability modifier is identified, or unless viscous forces or buoyancy enable forced imbibition, chemical wettability modification of fractured oil-wet carbonate rock does not provide an economically interesting opportunity. Introduction Rock fractures provide comparatively highly permeable flow paths through oil reservoirs. In a densely fractured reservoir the permeability contrast between the fracture network and the oil-bearing matrix can be significant. In that case the viscous pressure differential across individual matrix blocks can be too small to release oil from the blocks under waterflood, leading to a poor recovery. Depending on the wetting state of the matrix and its initial water saturation Swi capillary action can cause imbibition of water up to a "spontaneous" equilibrium saturation, commonly denoted as Sspw. At this saturation, however, the capillary pressure inside the matrix block coincides with that in the fracture and recovery ceases. Experience has shown that carbonate fields often are preferentially oil-wet [1, 2], which is synonymous with Sspw being close or equal to Swi, and thus exhibit very limited recovery during primary and secondary production.
- Europe (1.00)
- Asia (0.68)
- North America > United States > Texas (0.47)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.54)
- Geology > Geological Subdiscipline (0.34)
- 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 > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)