With a resurgence of chemical EOR opportunities throughout the world, high concentration surfactant design has re-emerged its uneconomic face. High concentration surfactant formulation is the micellar polymer design from the past that produced high oil recoveries in the lab but were uneconomic in the field. Formulation designs must consider factors beyond simply oil recovery for economic success and to minimize production issues in the field. Analysis and comparison of micellar polymer design projects from the 1970-1980s to current SP/ASP formulation designs are discussed. A simple formulation cost calculator is showcased, costs of all formulations are presented, and price per incremental barrel produced (chemical cost only) are shown assuming a 0.1 PV of incremental recovery. Analysis concludes the following: Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion. Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects. Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than $20 of chemical per barrel of incremental oil is unlikely to be economic with $50/bbl oil. Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success. The industry is taking steps back to an uneconomic time of chemical EOR by obscuring the difference between designs meant to increase reserves (economic oil) versus those that serve an academic or research purpose. Operators are unwittingly paying the price to advance the science of chemical EOR when service companies provide formulations that are not economic. This paper is meant to remind the industry that high concentration surfactant formulations never were economic and certainly will not be economic in today's price environment.

A Single Well Chemical Tracer Test (SWCTT) was performed in the Sabriyah Lower Burgan reservoir to provide an estimate of alkaline-surfactant-polymer (ASP) flood viability. Only an alkaline-surfactant (AS) solution was injected. As a result, oil de-saturation results for an ASP solution needed to be estimated to provide oil recovery potential to decide whether to proceed to a multi-well pilot. The SWCTT had a test radius of approximately 23 ft with a pore volume of 500 bbls. Three pore volumes of water were injected prior to determining the waterflood residual oil saturation. Injection was at a much lower rate and higher pressure than was observed with subsequent production of water. As a result, water injection was suspended and three acid jobs were performed. Water was then injected for eight pore volumes followed by SWCTT oil saturation determination. Oil saturation at waterflood residual was 35 % PV. An AS solution, totaling 1.2 pore volumes, was then injected which reduced the residual oil saturation to 27 % PV. Numerical simulation matched the SWCTT performance in SA-Well A; waterflood residual oil saturation of 36 % PV and AS residual oil saturation equal to 28 % PV were achieved. Injection of ASP solution instead of AS indicated an additional oil saturation reduction to 20 % PV. Waterflood residual oil saturations from constant rate laboratory linear corefloods with live and dead crude oil averaged 42 % PV and 40 % PV, respectively. Dead crude oil linear coreflood mimicking the injection sequence of the SWCTT resulted in AS solution reducing oil saturation from a waterflood residual of 35 % PV to 34 % PV. Injection of ASP solution further reduced the oil saturation to a final oil saturation of 17 % PV. Live crude oil linear corefloods with ASP injection after waterflood reduced oil saturation to 12 % PV. Constant pressure linear corefloods with dead crude oil waterflood residual oil saturation was 43 % PV and a subsequent ASP injection sequence reduced the oil saturation to 12 % PV. Coreflood and numerical simulation extrapolations suggest that if polymer was included with the AS solution in the SWCTT, oil saturation in SA-Well A Lower Burgan could have been reduced to 17 % PV or lower. Well injection rates were much lower than production rates. Injection rate was 550 bbl/day at 4600 psi downhole pressure while the well brine production rate was up to 2400 bbl/day. Low injectivity was observed during initial seawater injection, which resulted in reducing the proposed SWCTT test pore volume and elimination of polymer from the chemical formulation. Expected bottomhole pressure was 3200 psi while actual bottomhole pressure was 3800 psi, the original reservoir pressure. A conceptual mechanistic model of the Sabriyah Lower Burgan with the high reservoir pressure concluded that the lower injectivity was not caused by microscale rock properties but by the presence of a steady state boundary (constant pressure boundary) in close proximity to the evaluated well.

An alkaline-surfactant-polymer (ASP) pilot in a regular five spot well pattern is underway in the Sabriyah Mauddud (SAMA) reservoir in Kuwait. High divalent cation concentrations in formation water and high carbonate concentration of the ASP formulation makes the formation of calcite scale a concern. The main objective of this study is to investigate the severity of the calcium carbonate (CaCO3) scaling issues in the central producer in pursuit of a risk mitigation strategy to treat the potential scale deposition and reduce the flow assurance challenges. Calcite scaling risk in terms of Saturation Ratio (SR) and scale mass (in mg/L of produced water) in the pilot producer is potentially very severe and the probability of forming calcium carbonate scale at the production well is high. Produced Ca2+ concentration is high (> 800 mg/l), which makes the equilibrated calcite SR severe (> 500) and results in significant amount of scale mass precipitation. Different flooding strategies were modelled to evaluate a variety of flood design options to mitigate scale risks (varying slug size, Na2CO3 concentration, and volume of softened pre-flush brine), with marginal impact on scale formation. When the high permeability contrast of the different layers is reduced (to mimic gel injection), calcite SR and precipitated scale mass is significantly reduced to manageable levels. The option of injecting a weak acid in the production well downhole can suppress most of the expected calcite scale through reduction of the brine pH in the produced fluid stream for the ASP flood. Weak acid concentrations in the range of 4,000 to 5,000 mg/l are forecast to mitigate scale formation.

Improving water-flood efficiency in heterogeneous reservoirs with high permeability contrast is of high strategic importance to maximize oil gains, debottleneck production facilities and alleviate water-handling constraints. This paper presents key lab, simulation and field design insights to implement Deep Reservoir Conformance Control (DRCC) in the Wara formation of the Greater Burgan Field. Prior technical assessment and high-resolution streamline modelling are covered in other technical publications. Full-field high-resolution streamline reservoir simulations have been used to identify 23 candidate injectors for DRCC. The wells having one layer taking more than 50% of the total water injected were considered as good candidates for DRCC to mitigate water channeling challenges and increase sweep efficiency accordingly. Mechanical water shut-off options were considered, but it was confirmed that near-wellbore solutions do not adequately address deep reservoir conformance issues and can compromise water accessibility to unswept oil zones. Furthermore, mechanical water shut-off options require recompletion and can be expensive and difficult to deploy. To overcome these drawbacks, DRCC has been evaluated in an integrated laboratory and simulation study to design a field implementation plan. The recommended DRCC approach involves injecting a microgel followed by a gel. The microgel enables deep treatment while the gel strengthen Permeability Reduction near the well. Laboratory evaluation qualified a microgel having a size of around 2 µm and a gel combining water-soluble polymer with an organic crosslinker. Gelation time was 2 days and full gel consistency was obtained after two weeks, under the form of a strong and slightly deformable gel (E-F on Sydansk scale). Permeability reduction post gelation was as high as 10,000 times. Reservoir simulations were executed to validate this approach, size-up the treatment and forecast performance. A pattern involving an injector and a producer well was selected. Laboratory coreflood data were used as input for the simulations. The combination of microgel followed by gel with a total volume of around 6000 bbl, pumped in two days, induces a gain in oil production of around 20 to 50% in 10 years. Simulation shows improvement of both vertical and areal sweep efficiency. Moreover, the gain appears very early after chemical injection. The combination of microgel and gel gives an efficient in-depth conformance system that can increase waterflood efficiency in formations such as Wara. This innovative approach has high potential in multi-layer high-permeability heterogeneous sandstone reservoirs.

A one-spot pilot was successfully performed in the Sabriaya-Mauddud (SAMA) formation in Kuwait to demonstrate the feasibility of using alkaline-surfactant-polymer (ASP) injection to increase oil recovery from a giant carbonate reservoir. Two Single Well Chemical Tracer (SWCT) tests were performed on the SAMA test well (Well A) to measure the effectiveness of ASP injection in mobilizing waterflood residual oil saturation. The first SWCT test (Test #1) measured the waterflood residual oil saturation (Sorw) after a 10 PV seawater injection. This was followed by the second SWCT test (Test #2) to measure the oil saturation (Sorc) remaining after ASP chemical injection, comprised of: a 0.12 PV alkaline pre-flush; a 0.22 PV injection of ASP; a 0.68 PV injection of polymer in alkali solution; and a 1.00 PV injection of polymer. The difference in residual oil saturation from Tests #1 and #2 quantitatively determines the overall displacement efficiency of ASP injection. Tests #1 and 2 were performed post water and ASP flooding by injecting dilute SWCT tracer chemicals, including a hydrolyzing, partitioning ester (ethyl acetate) and two alcohols (n-propyl alcohol and isopropyl alcohol) that serve as a cover tracer and material balance tracer, respectively. Residual oil saturation post seawater injection was around 28% (+/- 3%) and following ASP flooding it was reduced to 4% (+/- 3%). These encouraging results confirm the effectiveness of ASP flooding in improving incremental oil recovery relative to waterflooding using seawater. This paper demonstrates the feasibility of applying ASP flooding to increase oil recovery from carbonate reservoirs. The reported findings will be used to optimize and de-risk the implementation in multiwell/pattern ASP injection.