This paper discusses the design and implementation of a Single Well Chemical Tracer Test (SWCTT) to evaluate the efficacy of a lab-optimized surfactant-polymer formulation for the Raudhatain Lower Burgan (RALB) reservoir in North Kuwait. A SWCTT was designed upon completing extensive lab and simulation work as discussed in a previous publication (Al-Murayri et al. 2017 and Al-Murayri et al. 2018). SWCTT design work was aimed at confirming the optimal injection/production sequence determined at core flood scale in terms of minimal volumes, rates and duration. The main uncertainties were assessed using numerous sensitivity scenarios. Afterwards, the SWCTT was implemented in the field and the results were carefully analyzed and compared to previously obtained lab andsimulation results. The main objective of this SWCTT was to validate the efficacy of polymer and surfactant solutions in terms of residual oil saturation reduction and injectivity. This invovles comparing residual oil saturation estimates before and after chemical flooding while monitoring injection rates and corresponding wellhead pressures. The SWCTT injection sequence included the following steps:Initial water-flooding, followed by tracer injection, soaking and production to measure oil saturation post water flooding.Pre-flush followed by a main-slug (with 5,000 ppm of surfactant and 500 ppm of polymer) and a post-flush (with only polymer).Sea-water push, followed by tracer injection, soaking and production to measure oil saturation post chemical flooding. Simulation work prior to the execution of the SWCTT test showed encouraging oil desaturation results post chemical flooding within a distance of 10 ft from the well. However, upon analyzing the pilot results, it was realized that there is a gap between the actual SWCTT results and previously obtained lab andsimulation results. This paper sheds light on the design and implementation of the above-mentioned SWCTTwith emphasis on the potential reasons for the realized gap between actual field data and lab/simulation results. The insights from this study are expected to assist in further optimization of surfactant-polymer flooding to economically increase oil recovery from relatively mature reservoirs.

Single Well Chemical Tracer Testing (SWCTT) is traditionally performed to determine oil saturation after waterflooding and after enhanced oil recovery techniques. Raudhatain Lower Burgan (RALB) and Sabriyah Lower Burgan (SALB) SWCTT oil saturation reduction due to injection of surfactant-polymer and alkali-surfactant solutions, respectively, were 7 and 8% OOIP, respectively. During SWCTT, injection rate and surface pressure are routinely measured for each injected solution. Injection rate and surface pressure permit additional determinations to be made as outlined below: Pseudo resistance factor to any fluid "i" can be calculated and, from this, changes in injectivity can be determinedFlowing viscosity of injected fluids relative to waterEffective permeability to injected fluidsInjectivity factors Pseudo resistance factor for RALB continually increased with seawater injection, from 0.5 to 1.0 indicating a reduction of kwro to approximately half and a twofold loss of injectivity. SALB kwro showed a three-fold loss of injectivity with seawater injection (pseudo resistance factor increased to 1.0 from 0.36). RALB pseudo residual resistance factor was 6.0 indicating a six-fold loss of injectivity due to surfactant-polymer and polymer drive solution injection even though the oil saturation was reduced by 7% OOIP. SALB pseudo resistance factor increased to 1.7 during alkaline-surfactant solution, indicating a loss of injectivity and an increase in flowing viscosity. SALB pseudo residual resistance factors were 0.89 to 1.06 suggesting no damage to reservoir rock and no loss to a slight increase of injectivity or an increase of kwro after an 8% OOIP saturation reduction. RALB surfactant-polymer rheometer viscosity was 0.55 cP while flowing viscosity was 0.21 cP as calculated from pseudo resistance factor data with the comparative polymer drive solution viscosities being 1.9 cP rheometer and 0.16 cP flowing. SALB alkaline-surfactant solution flowing viscosity was calculated to be 0.80 cP compared to water viscosity of 0.50 cP. Calculated SALB kwro values for injection of water, alkaline-surfactant, and water flush after alkaline-surfactant are 0.012, 0.007, and 0.011 to 0.015mD, respectively. Calculated RALB kwro values for injection of seawater and seawater flush after surfactant-polymer/polymer flush are 0.019 and 0.004 mD.

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.