New operational application using a field-tested stimulation technology that was previously only available as a permanent installation as part of the lower completion was recently successfully applied as a retrievable option. This alternative installation method reduces rig time, overall project cost and returns the wellbore to Open Hole should it be required for post stimulation logging or future interventions. The lower completion stimulation technology consists of standard liner pipe that is made up offline to short Subs and the sub-assemblies are then preloaded with four tubes up to 40 feet in length, each tube with a jetting nozzle on the end. The liner string with casing packer was run into the open-hole well section with Subs positioned across the formation where stimulation was required. 15% HCl acid was then pumped at the designed rate that resulted in the penetration of the tubes into formation. Post stimulation the complete liner assembly was then retrieved by releasing packer with straight pull and shearing tubes that has entered the formation (the penetrated needles remain inside the formation). Many operational challenges were overcome by the PDO’s drilling team in order to complete this first of its kind installation utilizing multiple running string combinations and a small work over rig (Max 125 kdan) in order to keep the overall project cost down.
Narwal, Tushar (Petroleum Development Oman PDO) | Alias, Zaal (Petroleum Development Oman PDO) | Kumar, Kamlesh (Petroleum Development Oman PDO) | Abri, Zahir (Petroleum Development Oman PDO) | Dickson, Sara-Jane (Petroleum Development Oman PDO) | Hadhrami, Abdullah (Petroleum Development Oman PDO)
In Southern Oman, PDO is producing from several critically sour fields (1-10% H2S). Initial flow assurance studies from these fields based on available data at the time did not predict asphaltene plugging issues in depletion mode for most of the fields. However, over the period, wells from one particular field (Field SA3) started experiencing asphaltene deposition in the wellbore, which initially affected only surveillance activities but later led to significant production deferment and posed operational challenges. This paper discusses the asphaltene management strategy developed by the team to tackle asphaltene problem in a systematic manner by improving the current asphaltene detection and cleanout techniques, which led to to reduction in unscheduled deferment by 50% and the intervention costs by 20-25%. This work also describes the potential asphaltene risks during gas injection based on an asphaltene study performed on downhole samples.
Kumar, Kamlesh (Petroleum Development Oman) | Awang, Zaidi (Petroleum Development Oman) | Azzazi, Mohamed (Petroleum Development Oman) | Hamdi, Abdullah (Petroleum Development Oman) | Hughes, Brendan (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman)
The microporous rock types in Upper Shuaiba are low permeability ( 1mD) rocks occurring in thin (2-5 m) formations within the extensive Upper Shuaiba carbonate formations in Lekhwair. These microporous rocks constitute a significant volume of hydrocarbon in-place. Unlike the higher quality rudist-rich and grainstone rock types, appraisal pilots in the microporous areas have shown poor performance with waterflood development, which is the preferred development concept in the entire Lekhwair field. Two work streams are active in parallel to identify a technically and commercially feasible development option: Phase 1, technology trials to enable a successful waterflood implementation, and Phase 2, further studies to screen the potential of enhanced oil recovery (EOR) techniques and other light tight oil development. The technology trial work stream, initially considered four initiatives targeting injectivity improvement. To date, trials are complete for abrasive jetting and designer acid stimulation, early results are available for Directional Acid Jetting, and evaluation of Fracture Aligned Sweep Technology (FAST) is ongoing with hydraulic fracturing evaluation accelerated to Phase 1 due to synergies with the FAST evaluation.
Kumar, Kamlesh (Petroleum Development Oman) | Azzazi, Mohamed (Petroleum Development Oman) | Hamdi, Abdullah (Petroleum Development Oman) | Awang, Zaidi (Petroleum Development Oman) | Nicholls, Christopher (Petroleum Development Oman) | Lawati, Yousuf (Petroleum Development Oman) | Huseini, Hamood (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman) | Sharji, Hamed (Petroleum Development Oman)
The Upper Shuaiba reservoirs in Lekhwair consist of carbonate formations extending over a very large area (40 km × 40 km). Earlier development projects identified thicker, well-appraised formations, resulting in successful waterfloods. In contrast, challenges have been encountered in some of the waterflood pilots attempting to unlock future development areas. An integrated evaluation of these poor performing areas led to the development of a rock type catalogue that mapped out different rock types and their properties. Initial developments were mostly in high permeability rock types (Rudist Rich and Grainstone) whilst the underperforming pilots are associated with microporous rock characterized by low permeability (~1 mD) and thin formations (2-5m). These microporous rocks are associated with a large hydrocarbon volume in place. Resolving this development challenge is critical in maintaining the company's long-term production targets.
Waterflood is the preferred development concept as it is in line with the existing facilities and infrastructure. The existing pilots demonstrate that low water injectivity/throughput is the key challenge to waterflood feasibility. Conventional acid stimulation does not work in these formations. Four different initiatives, in addition to injection water quality monitoring and improvements, are being tried to ensure successful maturation of microporous resources: Abrasive Jetting: used to create small tunnels up to 3m into the reservoir. Controlled Directional Acid Jetting: using acid to create multiple small laterals (up to 12 m in length) into the reservoir. Designer Acid: acid tailored to improve conventional acid stimulation. Fracture Aligned Sweep Technology (FAST) as implemented in Halfdan field; which creates longitudinal fractures along the length of the well.
Abrasive Jetting: used to create small tunnels up to 3m into the reservoir.
Controlled Directional Acid Jetting: using acid to create multiple small laterals (up to 12 m in length) into the reservoir.
Designer Acid: acid tailored to improve conventional acid stimulation.
Fracture Aligned Sweep Technology (FAST) as implemented in Halfdan field; which creates longitudinal fractures along the length of the well.
The outcome of this study includes identification and mapping of the different rocktypes across the entire Upper Shuaiba; waterflood performance assessment of microporous rocks and new technology trials to accelerate the development of microporous resources. Whilst abrasive jetting has achieved limited success in improving injectivity, result from designer acid stimulation was disappointing. The other two trials are still under evaluation. In case all the initiatives fail to establish the feasibility of waterflood, alternate developments mechanisms are proposed as Phase 2 in the strategy.
This paper highlights how integration between different disciplines can help in maturation of a large resource volume, whilst accelerating its development by standardization of designs.
The giant field is a geologically complex, faulted anticlinal structure trending east-west, with dips ranging from 0 to 60 degrees. After the current waterflood operations are completed, it is estimated that about 2/3 of oil originally in place will be left behind unrecovered. The combination of light oil gravity and relatively high reservoir pressures makes these reservoirs good candidates for miscible CO2 EOR. There are separate waterflood developments that have been identified as candidates for CO2 EOR. Results of the CO2 pilot provide further encouraging results that show better than expected CO2 injectivity and vertical sweep than waterflood and good displacement of the remaining oil saturation.
The subsurface team successfully used design of experiments to manage uncertainties in history matching and production forecast. Multiple static realizations honoring the key geological uncertainties were built. Based on ranking criteria developed, there were three static realizations chosen for history matching; that resulted in good history matches obtained for five different realizations. The history match model includes all the 500 wells, 70 years of historical production and water injection. All the history matches were within uncertainty ranges and were technically assured for use in CO2 EOR forecasting. Sector modeling was used to identify and rank different subsurface uncertainties and decisions. Experimental design was used to manage the uncertainties remaining after history match. Hundreds of realizations were simulated that incorporated several integrated development decisions such as injection scheme, development sequence, well spacing, completion strategy and well orientation. Simulation results for all the realizations (with different levels of heterogeneity) indicate that the range of recovery factors varies from 10% (P10) to 24% (P90). The simulated forecasts were also benchmarked against limited analog fields. The production curves are then upscaled to the whole field using a dimensionless curves approach in WellSpring. A methodology to integrate inputs from multiple disciplines (surface, subsurface, wells and CO2 source) was developed to different integrated filed development options.
The complexity, depth, and compartmentalization of the field create challenges that affect all aspects of the CO2 EOR field development including: scope for CO2 recovery, flood design options, data gathering needs, integration with existing waterflood, utilization of existing comingled wells, surface facilities and subsurface modeling for realistic production forecasting. Our work focuses on the selection of field development concepts and determining the economic viability whilst incorporating the best practices and lessons learned from the CO2 EOR industry to ensure top quartile performance.
Waterflooding recovers little oil from fractured carbonate reservoirs, if they are oil-wet or mixed-wet. Surfactant-aided gravity drainage has the potential to achieve significant oil recovery by wettability alteration and interfacial tension (IFT) reduction. The goal of this work is to investigate the mechanisms of wettability alteration by crude oil components and surfactants. Contact angles are measured on mineral plates treated with crude oils, crude oil components, and surfactants. Mineral surfaces are also studied by atomic force microscopy (AFM). Surfactant solution imbibition into parallel plates filled with a crude oil is investigated. Wettability of the plates is studied before and after imbibition. Results show that wettability is controlled by the adsorption of asphaltenes. Anionic surfactants can remove these adsorbed components from the mineral surface and induce preferential water wettability. Anionic surfactants studied can imbibe water into initially oil-wet parallel-plate assemblies faster than the cationic surfactant studied.
Waterflooding is an effective method to improve oil recovery from reservoirs. For fractured reservoirs, waterflooding is effective only when water imbibes into the matrix spontaneously. If the matrix is oil-wet, the injected water displaces the oil only from the fractures. Water does not imbibe into the oil-wet matrix because of negative capillary pressure, resulting in very low oil recovery. Thus there is a need of tertiary or enhanced oil recovery techniques like surfactant flooding (Bragg et al. 1982; Kalpakci et al. 1990; Krumrine et al. 1982a; Krumrine et al. 1982b; Falls et al. 1992) to maximize production from such reservoirs. These techniques were developed in 1960s through 1980s for sandstone reservoirs, but were not widely applied because of low oil prices.
Austad et al. (Austad and Milter 1997; Standnes and Austad 2000a; Standnes and Austad 2000b; Standnes and Austad 2003c) have recently demonstrated that surfactant flooding in chalk cores can change the wettability from oil-wet to water-wet conditions, thus leading to higher oil recovery (~70 % as compared to 5% when using pure brine). In 2003 (Standnes and Austad 2003a; Standnes and Austad 2003b; Strand et al. 2003), they identified cheap commercial cationic surfactants, C10NH2 and bioderivatives from the coconut palm termed Arquad and Dodigen (priced at US $3 per kg). These surfactants could recover 50 to 90% of oil in laboratory experiments. However, the cost involved is still high because of the required high concentration (~1 wt%) and thus there is a need to evaluate other surfactants. The advantage of using cationic surfactants for carbonates is that they have the same charge as the carbonate surfaces and thus have low adsorption. Nonionic surfactants and anionic surfactants have been tested by Chen et al. (2001) in both laboratory experiments and field pilots. Computed tomography scans revealed that surfactant imbibition was caused by countercurrent flow in the beginning and gravity-driven flow during the later stages.
The basic idea behind these techniques is to alter wettability (from oil-wet to water-wet) and lower interfacial tension. Hirasaki and Zhang (2004) have studied different ethoxy and propoxy sulfates to achieve very low interfacial tension and alter wettability from oil-wet to intermediate-wet in laboratory experiments. The presence of Na2CO3 reduces the adsorption of anionic surfactant by lowering the zeta potential of calcite surfaces, and thus dilute anionic surfactant/alkali solution flooding seems to be very promising in recovering oil from oil-wet fractured carbonate reservoirs.
It is very important to understand the mechanism of wettability alteration to design effective surfactant treatments and identify the components of oil responsible for making a surface oil-wet. It is postulated that oil is often produced in source rocks and then migrates into originally water-wet reservoirs. Some of the ionic/polar components of crude oil, mostly asphaltenes and resins, collect at the water/oil interface (Freer et al. 2003) and adsorb onto the mineral surface, thus rendering the surface oil-wet.
In this work, we try to understand the nature of the adsorbed components by AFM. Recently, AFM has been used extensively to get the force-distance measurements between a tip and a surface. These force measurements can be used to calculate the surface energies using the Johnson-Kendall-Roberts (JKR), the Derjaguin-Muller-Toporov (DMT), and like theories (van der Vegte and Hadziioannou 1997; Schneider et al. 2003). AFM is also used extensively for imaging surfaces. It can be used in the contact mode for hard surfaces and in the tapping mode for soft surfaces. It can be used to image dry surfaces or wet surfaces; tapping mode in water is a relatively new technique. AFM images have been used to confirm the deposition of oil components on mineral surfaces (Buckley and Lord 2003; Toulhoat et al. 1994). In this work, crude-oil-treated mica surface is probed using atomic force microscopy before and after surfactant treatment to study the effects of surfactant. AFM measurements are correlated with contact-angle measurements. We also study surfactant solution imbibition into an initially oil-wet parallel plate assembly to relate wettability to oil recovery. Our experimental methodology is described in the next section, the results are discussed in the following section, and the conclusions are summarized in the last section.
The goal of this work is to develop a compositional model for WAG injection in a medium-viscosity oil, low-temperature reservoir like Schrader Bluff Pool in the Milne Point Unit, Alaska. Compositional simulation of WAG displacement with CO2-NGL and Prudhoe Bay gas-NGL mixtures shows that three-hydrocarbon phases form in situ because of low temperature. A four-phase relative permeability formulation has been developed by considering the mixed-wettability of the formation and the saturation paths. The simulation results are compared with the laboratory experimental results from the literature. The sensitivity of the laboratory-scale oil recovery to relative permeability, pressure and solvent composition is studied. The sensitivity of oil recovery in a 2D quarter five-spot pattern to relative permeability, WAG ratio, slug size is also studied. CO2 - NGL mixture is a very effective solvent for this reservoir. The minimum miscibility enrichment is more sensitive to pressure for Prudhoe Bay gas - NGL mixtures than in the case of CO2 - NGL mixtures. The oil production rate is sensitive to relative permeability formulation. Oil recovery is faster at lower WAG ratio and higher slug size.