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The objective of injecting polymer in brown fields is to increase recovery beyond primary and secondary recovery mechanisms. However, generally it is difficult to achieve adequate (viscous) polymer injectivity in depleted sandstone reservoirs without fracturing. Therefore, monitoring fracture propagation is required in order to control vertical conformance and areal sweep and avoid early polymer breakthrough. Different surveillance methods are used to identify the existence and properties of fractures in polymer injectors. Pressure Fall off (PFO) survey data in conjunction with time-lapse temperature surveys are extensively used to determine the fracture dimensions. PFO tests in Polymer injectors have particular characteristics since they are influenced by shear-dependent viscosity seen in non-Newtonian fluids. A specially developed Injection Fall-off (IFO) model was used to determine fracture dimensions which is based on exact semi-analytical solution to the fully transient elliptical fluid flow equation around a closing dynamic fracture developed by Shell, (Van den Hoek 2005), as static fracture models are inadequate. This paper presents different phenomena in polymer injection seen in PFO tests such as fracture closure, the effect in-situ polymer rheology and the detection of the polymer front. The paper demonstrates the effect of liquid-level drop observed in PFO survey in under-pressured reservoirs and its impact on determining fracture and some other reservoir properties. It also shows how plot-overlays of time lapse PFO's for a particular well can be used to track changes in fracture dimensions. All of these are illustrated by a number of field examples of polymer PFO which also demonstrate the calculated fracture dimensions from the data. Finally, some recommended best practices are suggested for fracture monitoring. IntroductionThe large sandstone brown field that the polymer injection is taking place in is located in the eastern side of the South Oman basin. The oil is heavy, 22 API and viscous, 90 cP. The field is highly heterogeneous with sand, diamictite and shale bodies. Nonetheless in the main reservoir units the Net Sand to Gross reservoir ratio approaches one and the permeability can range up many Darcies. The main objective of injecting polymer is to increase the recovery beyond the primary and secondary recovery mechanisms by improving the sweep efficiency (figure1). In such heterogeneous reservoir, it is difficult to achieve an adequate viscous fluid injection under matrix condition in depleted sandstone reservoir. Therefore, Polymer injection was designed to be injected under controlled fracture conditions where the fracture length should not exceed 1/3 of the distance between injector and producers over the life of the project. This requires intensive qualitative and quantitative monitoring of the fracture dimensions through different surveillance techniques to control the vertical conformance and avoid early breakthrough of the polymer.

A field in Southern Oman has been identified as a potential target for Alkali-Surfactant-Polymer (ASP) flooding. Experimental investigations showed that ASP flood recovers more than 90% of waterflood remaining oil saturation. Simulation study showed that ASP increases the field recovery factor by more than 20% over waterflood or 12% over polymer flood. The potential size of the prize by ASP in this field alone is significant. The successful ASP single well chemical tracer test (SWCCT) and micro-pilot in this field validated the lab experimental results and demonstrated the significant desaturation by ASP and the extremely low oil residual after ASP. The ASP pilot was designed and initiated to de-risk and underpin the financial investment decision for a full-field implementation. The ASP pilot is designed as a small 1.4 acres (75m × 75m) inverted 5-spot pattern. It ensures completion of the field trial within one year of ASP flood. The pilot was commissioned in Q1 2014 with water pre-flush and the first ASP injection is anticipated for Q1 2016. A dynamic model was constructed and simulation was carried out. A comprehensive surveillance program was included in the pilot design and is being executed successfully. Surveillance data provide critical information to understand pattern communication, fluid flow path and reservoir characteristics. This paper will describe the results and analysis of some waterflood surveillance data and the integrated workflow of history matching. During the ASP pilot drilling campaign in 2013, an unexpected fault was encountered crossing the well pattern. This introduced an element of uncertainty regarding pattern communication. Pressure data and a passive tracer test confirmed the connectivity between the injector to 4 producers and that the fault is non-sealing. Initially the sector model was built with one fault across the pilot area, but the fluid communication in the pattern revealed by analysis of tracer suggested possible different geological realizations than the initial model. Therefore several static geological models were generated to reduce the uncertainties on history match. Well conformances were determined by PLT and DTS/DAS and were incorporated in the dynamic model. The time-lapse NMR log in the observation well provides insights on sweep, desaturation and micro displacement efficiency. Establishing and building a waterflood baseline is the foundation for the next phase of ASP implementation. This paper will share the analysis, learnings and practical implications of the pilot to date.

Alkali Surfactant Polymer (ASP) flooding was piloted in 2016 in a clastic field in Southern Oman. One of the main risks identified prior to the pilot is the impact of the produced ASP chemicals on the surface oil/water separation. To un-risk this issue, a custom-built fluid treatment facility (called flow-loop) was constructed to treat ASP produced fluids and determine its impact on the larger scale system. The flow-loop contains the typical technologies currently deployed in the field for processing produced crude (i.e. oil heaters and separators) with new technologies (bulk fluids heater, electrostatic desalter and new types of demulsifiers) in case existing production system is not adequate to produced fluid. Three groups of tests were conducted over a period of 12 months; the first part was the baseline tests where the performance of the system without any produced ASP chemicals is tested when operating as close as possible to the operating conditions of the existing field production station. Following the baseline test, more tests which were called optimized baseline tests were conducted to determine the impact of the technologies not deployed in the current production station in improving the oil and water separation. That included increasing the bulk heater temperature, oil heater temperature, increasing the incumbent demulsifier rate and applying the electrostatic heater current (crude viscosity is a few hundred at ambient temperature). The flow-loop was able to dehydrate crude quality of 1-2.5% BS&W and 100 ppm oil in water during the baseline test. The flow-loop was able to achieve 0.6% BS&W during optimized baseline tests. The second part was the online produced ASP slug chemicals impact test, which was the performance of the system when the chemicals reached the pilot producers, by operating with the baseline operating conditions and by attempting to improve the performance by operating the new fluid treatment technologies. The flow-loop could dehydrate the crude close to the baseline quality with the ASP chemicals naturally produced to surface (typical values measured are in the range of: pH= 9.3, Salinity = 6000 ppm, water viscosity= 15 cP at reservoir conditions, surfactant= 100 ppm), however more dehydration capacity is required with ASP being present. Significant water quality deterioration was seen with presence of ASP chemicals, but application of new demulsifier technologies could mitigate water quality to normal levels (comparable to conventional crude). The third part was like the second part but with additional surfactant injected directly to the surface producer aiming to increase the concentration of ASP slug to determine the impact of the higher surfactant concentrations (pH= 9.3, Water Viscosity= 10cP, surfactant= 400 ppm) on treatment facilities. The flow-loop was able to dehydrate oil but more separation capacity with appropriate demulsifier is required to achieve sellable oil specs. The water quality deteriorated significantly and this could also be mitigated to normal water qualities by appropriate demulsifier and optimized dosing.

Alkaline Surfactant Polymer (ASP) flooding was identified as a potential field development option for a clastic field in Southern Sultanate of Oman. Extensive laboratory studies and field tests have been conducted to evaluate and mature this development option. Core floods showed that ASP can recover more than 90% of the oil remaining after waterflood resulting in remaining oil saturation below 5%. Simulation studies showed that ASP can potentially increase the field recovery factor by more than 20% over waterflood or 10% over polymer flood. A successful ASP single-well tracer test (SWCTT) and a micro-pilot in this field validated the laboratory results, confirmed the significant desaturation by ASP and the low residual oil saturation after ASP. The potential size of the prize for ASP flooding in this field alone is significant. Upon further evaluation of ASP as a development option, significant risks and uncertainties associated with implementing ASP at field scale were identified. An ASP continuous injection pilot was designed with well-defined objectives to reduce the risks and to quantify the uncertainties. In this pilot, the ASP process was evaluated in one of the main producing zones in the flank of the field utilizing a small (75m × 75m or 1.4 acres) inverted 5-spot pattern with a total of 7 wells (4 producers, 1 injector, 1 observation well, and 1 sampling well). The short injector-to-producer distance enabled a quick response and ensured completion of the field trial within one year at the target injection rate. The pilot was commissioned in Q1 2014 with water pre-flush to establish a waterflood baseline. Injection of the 0.3 PV ASP-slug started in February 2016, followed by 0.9 PV of polymer and a water post flush that was concluded in December 2016. A custom-built surface facility was constructed to mix and inject the required chemicals and to assess and treat produced fluids through a specialized flow loop. Dedicated Multi Phase Flow Meters (MPFM) were deployed at each producing well to provide accurate phase rates to quantify ASP incremental oil volumes. Detailed chemical analyses of injected and produced fluids were conducted throughout the pilot execution. Desaturation assessments were carried out through detailed surveillance activities in the dedicated logging observation well that involved a comprehensive suite of logs and evaluation tools, including time-lapse Nuclear Magnetic Resonance (NMR) for saturation monitoring that were used for the first time in the field. The pilot achieved stable and safe operations with good injectivity, uptime, accurate chemical dosing, sampling and analysis as well as detailed surveillance. It recovered a significant incremental volume of oil above waterflood from decline curve analysis vs. a target of 20%, hence doubling the recovery as achieved with waterflood. Significant water cut reversal (25% - 30%) in producers and 31% reduction in oil saturation in the observation well due to ASP were observed by the time lapse NMR data. No injectivity issues were encountered with 50cP ASP and polymer chase. No scale was encountered during pilot period due to the successful and early deployment of scale inhibitor. The pilot produced saleable quality oil, free from emulsion with negligible increase in BSW over waterflood. This paper re-iterates the pilot objectives and design, summarizes the pilot results, including well performance, chemical analysis and surveillance data, surface facility performance during pilot execution, and the dynamic simulation and analysis of the pilot performance.