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.

Mature reservoirs in the Middle East undergoing water-flooding present multiple challenges in the sheer number of wells in operation, coupled with the large volumes of water being produced, handled, treated and injected. Consequently, this calls for practical options to improve water flood efficiency and alleviate water handling constraints. This paper presents a systematic workflow encompassing numerical modeling, laboratory evaluation and field implementation to address injection conformance problems encountered in the highly heterogeneous clastic Wara Formation of the Greater Burgan field as outlined below: Stage 1: Preliminary technical assessment to identify candidate areas and wells Stage 2: Fit-for-purpose streamline simulation to support and prioritize selection of candidate wells Stage 3: Lab evaluation to select applicable chemistries to specific reservoir properties coupled with numerical simulation to forecast field performance Stage 4: Design and implement Deep Reservoir Conformance Control (DRCC) This paper focuses on Stages 1 and 2. Stages 3 and 4 will be addressed in other technical publications. The wells that were assessed as candidates had to comply with a set of key pre-defined criteria, including but not limited to: Injectors with commingle or multizone completion High permeability contrast across completion zones Premature water/tracer breakthrough Significant non-uniform zonal intake Poor sweep efficiency and bypassed oil High water cut in nearby producers Injectors taking water on vacuum or showing higher than expected injectivity Following this, a further set of screening criteria was imposed. Zone injection >50% of total injection into the well plus cumulative well injection >1 million STBW. This allowed focusing on the high-impact injectors where DRCC needs to be deployed on priority. An existing history-matched full field simulation model was then executed. This generated subsurface connectivity data, represented as streamlines with attributes of connected pressures, saturations, pore volumes and flux between injector and producer wells, thereby providing both quantitative and visual indication of the degree of inter-well hydraulic connectivity between injectors and pertinent producers. Model validation was supported by comparing zonal intake surveys to simulated outcomes. Difference plots were utilized to highlight non-convergence between the simulated and measured data. Zonal injection rates were extracted and plotted over time and as time-series logs. This enabled quick identification of key zones with significant water intake. Further corroboration using zonal intake survey results was then performed. Potential impact of DRCC was simulated via effective transmissibility modification. An iterative approach was adopted to ensure that zonal intake does not exceed 50% for other zones in the well, following the reduction in the intake capacity of the originally dominant zone, thus resulting in the identification of 23 injectors. The presented workflow establishes a systematic evaluation of candidate wells based on a uniform set of governing criteria. Sensitivities could be tested and evaluated rapidly, thus guiding decision-making on field implementation.