Gels are a fluid-based system to which some solid-like structural properties have been imparted. In other words, gels are a fluid-based system within which the base fluid has acquired at least some 3D solid-like structural properties. These structural properties are often elastic in nature. All of the conformance improvement gels discussed are aqueous-based materials. The term "gel" as used in this page (unless specifically noted otherwise) refers to classical, continuous, bulk, and "relatively strong" gel material and does not refer to discontinuous, dispersed, "relatively weak," microgel particles in an aqueous solution.
Total has been operating oil and gas production from a series of heterogeneous carbonate reservoirs offshore Abu Dhabi since 1974. New technologies to increase oil recovery have been always tested and deployed on this field as tertiary gas injection since the 1990's or chemical EOR with a surfactant polymer pilot recently. On the same dynamic, we tested chemical water shut off treatment on two highly waterflooded wells with the injection of relative permeability modifiers (microgels).
This paper describes the full workflow followed for the pilot implementation and lessons learnt.
A particularity of this field is to produce in commingle oil from different thin reservoirs, with permeabilities ranging from to 0.5 to 50mD. Well production is combined through a single sliding sleeve, thus any mechanical shut off is impossible to block the water coming from the high permeability zones that is why the injection of RPM was considered.
Microgels were preferred over conventional polymers gels due to their higher resistance to salinity, shear, and H2S.
Laboratory studies were conducted to select the best microgel size and to obtain inputs for near well-bore model simulation (microgel adsorption, permeability reduction, injectivity). Numerical simulations were performed to predict the well responses and to define the optimal slug injection.
For this first pilot using microgels in high salinity environment, two vertical wells producing from two different reservoirs were tested, with watercut of 92 and 97%.
The microgel fluids were bullheaded into the whole perforated interval, the fluids were prepared on a nearby marine vessel; the operational challenges faced are detailed.
Preliminary results and way forward are described. The application of this microgel technology to high salinity and moderate temperature carbonate fields has a great potential to improve recovery in very mature fields at low cost.
The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low-salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently investigated by some reserchers. The main objective of this study was to determine whether the combining technologies can improve conformance control in fractured sandstone reservoirs. Semi-transparent five-spot models made of sandstone cores and acrylic plates were built. The effect of low-salinity waterflooding on oil recovery was studied. Models were designed with three parallel open fractures. Sodium chloride (1.0, 0.1, 0.01, and 0.001 wt. % NaCl) were used for brine flooding and 1.0 wt. % NaCl for preparing swollen PPG. Two microgel concentrations, 2000 PPM and 5000 PPM, with 850 micrometer particle size were used. Three cycles of low-salinity water were injected after the second conventional brine injection was completed. Oil recovery factor, water cut, injection pressure, microgel extruded pressure, fracture pressure (Pf), monitoring pressure (P1 and P2), and water residual resistance (Frrw) were measured. The interwell connectivity also was investigated. Laboratory experiments showed that the oil recovery factor, injection pressure, and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. The tortuous wormholes resulted highrer oil recovery than the straight wormholes and the oil recovery decreased as number of fratures and fracture width increased. The microgel concentration had a signicicant effect on plugging effeciecny; therefore, the 5000 PPM Microgel showed higher plugging efficiency than 2000 PPM. The result showed the interwell connectivity between the injector and producer decreased when low salinity waterflooding applied and increased the interwell connectivity between the injector and the monitoring points. The plugging efficiency, stabilized injection pressure, fracture pressure, monitoring pressure, and water residual resistance factor—all increased when the salinity of injected water decreased. Furthermore, the microgel strength decreased as brine concentration decreased. However, lower salinity water caused the incremental oil recovery factor to increase. Thus, there is a limitation in increasing the plugging efficiency under low salinity water. This limitation occurred when the brine injection pressure was less than the PPG’s extruded pressure. Combining two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control.
SMG Microgels are pre-gelled polymers having a narrow size distribution and behaving like large polymer molecules. Their stability is strongly enhanced by internal cross-links. Several SMG microgels having different chemical compositions and cross-link density, with a size of around 2 μm were submited to laboratory corefloodtests. SMG propagation in reservoirs is driven by a size exclusion mechanism. Microgel size prevents invasion of low permeability zones and creates flow resistance in high permeability zones by adsorption on the rock. The permeability cutoff can be tuned by microgel size and chemistry. Permeability reduction generated by SMGs is determined by the thickness of the adsorbed layer which is roughly the size of the microgel in solution. It is little dependent of the adsorption level. Adsorption depends on the chemical composition of the microgel and on the nature of the rock.
An SMG Microgel with soft consistency was selected for a Conformance Control field application in a heterogeneous sandstone reservoir. Reservoir permeability ranges between 10 mD and 1200 mD with an average permeability of around 200 mD. The pattern consists of one injection well surrounded by eleven offset producers. The injection lasted 3 months with a total volume of 9,000 m3. After a few months, six offset producers showed increase in oil rate along with a reduction of a few points of water cut. One well lost both water and oil, thus proving diversion to the other wells. The trend remains steadily established in the pattern with continuous increase in additional oil production. After two years, more than 33,000 bbl of additional oil has been produced, giving a ratio of less than 0.7 lb of microgel per extra barrel of oil.
Qiu, Yue (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology) | Wu, Fengxiang (Daqing Xinwantong Chemical Co. Ltd.)
This paper presents the detailed descriptions of successful field application for a high-temperature and high-salinity resistance microgel in a mature reservoir in the northwest part of China. The reservoir with low permeability (230 md) experienced serious vertical and lateral heterogeneity problems, which caused low sweep efficiency and high water-cut (more than 95%). The treatment was designed based on laboratory experiments and experience from previous field application, providing detailed information of mechanism of microgel treatment and project execution. Thermal stability test showed that the microgel could resist the salt concentration up to 230,000 ppm at 125 °C for more than 1 year. From the core analysis, permeability of the long-term water-flooded zone was measured around 1,489 md, proving the evidence that high-permeability zones existed. Pilot test has been done before field application and valuable experience about how to design the injection parameters was provided. According to the information from laboratory experiments and the pilot test, four injection wells associated with nine offset production wells were selected for microgel treatment. For about 10 months treatment, 169 t of microgel was injected by five slugs.
Gradually increased injection pressure suggested that microgel could be placed deeply into the reservoir. The ultimate incremental oil production was approximately 29,635.8 t with the water cut decreasing from 95.3% to 93.1%. Microgel can be successfully used in relative low permeability (230 md) reservoir with harsh conditions for conformance control.
SMG Microgels are pre-gelled polymers having a narrow size distribution and behaving like large polymer molecules whose stability is strongly enhanced by internal crosslinks. The largest species have a size of around 2 µm, which makes them suitable for Water Shutoff and Conformance Control applications in matrix reservoirs. SMG Microgels have been firstly used as water shutoff agents in gas storage wells and showed high efficiency to reduce water production while enhancing gas production. This paper reports a Conformance project which has been recently deployed in a heterogeneous sandstone reservoir. The pilot pattern consisted of one central injector, surrounded by 7 offset producers, with a spacing between 150 and 450 m. Reservoir permeability ranges between 10 and 1,000 mD with an average of 125 mD. Reservoir temperature is 48°C and salinity is 8,000 ppm TDS.
Soft SMG with size around 2 µm was chosen regarding reservoir conditions. Microgel size prevented invasion of lowest permeability zones and created flow resistance in highest permeability zones by adsorption on the rock. Microgel slug corresponded to 0.1 Pore Volume and was 10,000 m3. Microgel injection proceeded over a period of 3 months. WHP remained below max pressure authorized of 1,500 psi.
Closest producers responded within 3 months after microgel injection, with noticeable increase in oil rate along with a reduction of a few points of water cut. After one year 6 offset producers upon 7 were responding to the treatment. Three producers showed strong increase and sustained oil production, three had low response and one well lost both water and oil, showing diversion to the other wells. The trend remains steadily established in the pattern. After one year, 10,000 bbl of additional oil has been produced, along with a reduction of water production of 125,000 bbl.
This paper relates the successful water shut-off treatment of a heavy-oil Omani well combining the use of microgel and gel.
As many sandstone reservoir with strong aquifer in Southern Oman, this vertical well faced early water breakthrough along with sand production. Water cut increased dramatically until reaching 100%. The average permeability was around 500 mD but effective permeability ranged from milli Darcy to several Darcy. Due to well characteristics (several perforation intervals, gravel pack, etc…), it was not possible to identify and isolate the water production zones, which oriented the strategy towards the use of RPM products (Relative Permeability Modifiers). The treatment consisted of microgel and gel injections which were bullheaded into the whole open interval. After the treatment, the water cut dropped from 100% to 85% and sand production was stopped over a period of time superior to one year. The treatment was cost effective, producing more than 9000 bbl of extra oil in one year.
In this paper, we describe the treatment design methodology combining laboratory study and near wellbore simulations, and the optimization of injection sequences. Finally, the treatment execution is detailed followed by the presentation of the results obtained since the realization of the operations.
The results show that combining low-risk approach and low-cost RPM technology is an attractive way to restore productivity of watered out wells, in which conventional water shut-off zone isolation is not feasible.
Swellable packers are widely used to create annular seals between production casing and an open hole. The popularity of swell packers is due to their ease of deployment and streamlined design, which does not have moving parts to malfunction. The current water swell packer technology meets the swelling requirement in light monovalent brines, however, falls short of swelling requirements in heavy brines and especially divalent brines like CaCl2 and CaBr2. This work/paper presents the development of new swellable elastomers that exhibit superior swelling in divalent brines and enhanced mechanical properties compared to existing swellable compounds.
New swellable elastomers are made by blending newly developed swellable nanocomposite microgels with nitrile butadiene rubber (NBR). Nanocomposite microgels possess a unique polymer/nano-clay network structure in which nano-clay acts as a multifunctional cross-linker and leads to the formation of higher molecular weight polymer chains. As a result of the unique structure, the nanocomposite microgels exhibit better elastomeric behavior, higher swelling ratio and faster swelling kinetics compared to the conventional super absorbent polymer (SAP). The nanocomposite microgels were synthesized through the reverse-phase suspension polymerization method to achieve a gel particle size of less than 10 µm, which is essential for the fast swelling rate of the compound. A divalent brine-tolerant 2-acrylamido-2-methylpropane sulfonic acid (AMPS) monomer was selected for the synthesis to achieve divalent brine-swelling capability.
The new swellable elastomers exhibit a 100% volume increase within three days in 10% CaCl2 at 200° F, and a final volume swell of more than 200% for a 1-in. button sample. This volume swell of the button sample is four times higher than the current water swellable elastomers. The new swellable elastomers also exhibit better mechanical properties than current swellable compounds.
Newly developed swellable elastomers made by incorporating novel nanocomposite microgels in the base polymers offer swellable packers for heavy brine environments.