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.
Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.
An Alkaline-Surfactant-Polymer (ASP) project in the Instow field, Upper Shaunavon formation in Saskatchewan Canada was planned in three phases. The first two multi -well pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 35% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 47% PV ASP solution. Polymer drive continues in both phases with Phase 1 and Phase 2 injected volume being 55% PV and 35% PV, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.5% to 12 to 16% and an increase in oil rate from approximately 3,200 m3/m (20,000 bbl/m) to 8,300 m3/m (52,000 bbl/m) in Phase 1 and from 2,200 m3/m (14,000 bbl/m) to 7,800 m3/m (49,000 bbl/m) in Phase 2. Phase 1 pattern analysis indicates the pore volumes of ASP solution injected varied from 13% to 54% PV of ASP with oil recovery percentage increasing with increasing injected volume. Oil recoveries in the different patterns ranged from 3% OOIP up to 21% OOIP with lower oil recoveries correlating with lower volume of ASP injected. The response from some of the patterns correlates with coreflood results. Wells in common to the two phases show increase oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Oil recovery as of August 2019 is 60% OOIP for Phase 1 and 57% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost would be approximately C$26/bbl resulting in the decision to move forward with Phase 2.
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.
The Sabriyah Upper Burgan is a major oil reservoir in North Kuwait with high oil saturation and is currently considered for mobility control via polymer flooding. Although there is high confidence in the selected technology, there are technological and geologic challenges that must be understood to transition towards phased commercial field development. Engineering and geologic screening suggested that chemical flood technologies were superior to either miscible gas or waterflood technologies. Of the chemical flood technologies, mobility control flooding was considered the best choice due to available water ion composition and total dissolved solids (TDS). Evaluation of operational and economic considerations were instrumental in recommending mobility control polymer flooding for pilot testing. Laboratory selected acceptable polymer for use with coreflood incremental oil recovery being up to 9% OOIP. Numerical simulation recommended two commercial size pilots, a 3-pattern and a 5-pattern of irregular five spots, with forecast incremental oil recovery factors of 5.6% OOIP over waterflood. Geologic uncertainty is the greatest challenge in the oil and gas industry, which is exacerbated with any EOR project. Screening of the Upper Burgan reservoirs indicates that UB4 channel sands are the best candidates for EOR technologies. Reservoir quality is excellent and there is sufficient reservoir volume in the northwest quadrant of the field to justify not only a pilot but also future expansion. There is a limited edge water drive of unknown strength that will need to be assessed. The channel facies sandstones have porosities of +25%, permeabilities in the Darcy range, and initial oil saturations of +90%. Pore volume (PV) of the two recommended pilot varies from 29 to 45 million barrels. A total of 0.7 PV of polymer is expected to be injected in 5.6 and 7.9 years for the 3-pattern pilot and the 5-pattern pilot, respectively, with a water drive flush to follow for an additional 5 to 7 years. Incremental cost per incremental barrel of oil of a mobility control polymer flood which includes OPEX and CAPEX costs is $20 (USD). This paper evaluates the (commercial size) pilot design and addresses field development uncertainties.
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