Hydraulic fracturing is often used in unconventional shale reservoirs, and 50%–95% of the injected hydraulic fracturing fluid remains in the formation due to the capillary effect. This phenomenon has been observed in the Montney shale formation, Canada, where the flowback water recovery is generally less than 25%. Surfactant is one of the hydraulic fracturing fluid additives for reducing surface tension and capillary forces to facilitate water flowback recovery. Surfactant loss due to adsorption by the reservoir rocks reduces the chemical’s efficiency, and this causes water retention in the formation and reduces water flowback recovery. The compatibility of surfactant with reservoir rock is critical to minimize surfactant adsorption on the rock surface because this diminishes the primary function of the surfactant hydraulic fracturing fluid additive and to ensure cost-effectiveness. This study evaluates surfactant efficiency to improve flowback recovery for the Montney shale formation based on IFT, surface tension, and adsorption. This study evaluates surfactant performance and performs a fluid–fluid interaction experiment and fluid-rock compatibility investigation. Several commercial surfactants are screened for low interfacial tension and surface tension. Further analysis is carried out by evaluating the fluid-rock compatibility using the static soaking test at reservoir pressure and temperature. The pre-soaking and post-soaking test fluids were analyzed for water composition, liquid–liquid interfacial tension, surface tension, and pH. Results showed that the selected surfactant is a critical determiner of the hydraulic fracturing fluid performance. SOLOTERRA 938 is an anionic surfactant that has good compatibility with Montney shale formation. Unlike other non-ionic surfactants, SOLOTERRA 938 retains the interfacial tension and surface tension after seven days of interaction with reservoir rock. The interfacial tension remained unchanged at 0.1 mN/m. The surface tension decreased from 28.4 to 27.5 mN/m with air and from 21.7 to 20.8 mN/m with hydrocarbon because surfactant behavior changes with pH change. The surfactant concentration was measured using high-pressure liquid chromatography, and the loss was 12% after seven days of interaction with the reservoir rock (from 0.1 to 0.088wt%). The adsorption calculated based on the concentration volume showed a low value of between 0.43 and 0.97 mg/g rock.

Among the different Enhanced Oil Recovery methods being implemented in the matured fields of Malaysia,Immiscible Water Alternating Gas (iWAG) appears to be the most viable option. However, reduction in well injectivity and productivity would be very harmful to this process and render it ineffective. Therefore, extensive laboratory testing, interpretation and integration have been performed to reach the conclusions and recommendations presented in this paper.The target reservoirs in the Bokor are made up of unconsolidated and very heterogeneous rock with high permeability streaks. The mineralogy of the target reservoirs shows over 10% of clay, with abundance of kaolinites and illites which tend to cause fines migration and mixed layer illites/smectite which can swell. Therefore special handling of core samples is necessary for the laboratory testing; this includes flow through cleaning and critical point drying. The aim of the study is to establish the potential mechanisms of formation damage during the iWAG progress and determine preventive, mitigative measures and provide guidelines for treatment if damage occurs. The main focus is on formation damage by fines migration, dirty injection fluids (Mechanically induced damage)and clay swelling and de-flocculation (Chemical induced damage -fluid rock interaction) effect to Bokor field. The laboratory tests performed includes capillary suction time, filtration level test, critical velocity and fines stabilizer test, constant rate injectivity test and formation damage by iWAG injection test.Key areas of interesting findings include (1) Potential formation damage mechanism during the iWAG process (2) Strategies to prevent damage and improved injectivity, (3) Recommended treatment frequency based on injection half-life established in this study and (4) Field monitoring strategies.

No abstract

Heavy/ extra heavy oil has captured the global attention as an unconventional hydrocarbon resource which may satisfy the ever-increasing energy demand in the future. Heavy/ extra heavy oil is often characterized as viscous and immobile fluid with high content of impurities and heavy metals, such as Nickel and Vanadium. These inherited characteristics impose great challenges not only to oil recovery optimization, but also various costs pertaining to downstream processing. Due to this fact, reservoir modelling and simulation are commonly conducted to evaluate the performances of enhanced recovery processes at early project stage. In this paper, the conceptual models for Oilfield Alpha are developed using CMG STARS reservoir simulator. They are grouped into 3 categories, i.e. (I) Horizontal wells, (II) 5-spot pattern vertical wells and (III) Horizontal well pairs, based on the nature and well configuration of the recovery techniques. These techniques are Horizontal Well (HORZ), Steam Flooding (SF), Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD), Vapour Extraction (VAPEX) and some of their variations. Performance indicators, typically the Recovery Factor (RF) andCumulative Steam-Oil-Ratio (CSOR), for each model are evaluated and compared within the category. The simulation results generally show that, after 20 years of production, the thermal methods have prevalently higher oil recovery factor, i.e. 7 -37 % of OOIP, compared to that of cold methods, i.e. 8 -13 % of OOIP. Further sensitivity analysis on Expanding Solvent-SAGD (ES-SAGD) and VAPEX are also conducted in order to investigate the effects of injected fluid composition imposed on the process performance. From the results, 95 % of steam and 5 % binary components of C 3 and C 6 presents as the optimum injected fluid composition for ES-SAGD method. On the other hand, injected fluid comprising 60 % of C 1 and 40 % of C 3 delivers the best oil recovery factor for VAPEX method.