Enhanced Oil Recovery (EOR) methods are on the rise and Petroleum Development Oman (PDO) has successfully embarked on several projects including thermal recovery. Thermal EOR operations require rapid response and adaptation to the dynamic thermal conditions inherent within the reservoir. The challenges associated with Cyclic Steam Stimulation (CSS) necessitated a creative solution to maximize recovery and improve well management. A fit for purpose algorithm was developed to add flexibility while operating the well in combination with the Variable Speed Drive (VSD). An automation algorithm was developed to optimize oil recovery and accelerate peak oil throughout the CSS production cycle. This algorithm maximized inflow potential by creating a low fluid level above the pump and maintaining near pumped-off conditions. The project was named Beam Lift Auto Delivery Evolution (BLADE). Live control of the pumping unit provides equipment safe guarding while ensuring continuous operation within the defined envelope. This is achieved by applying real time assessment of pump fillage and temperature conditions. This approach optimized production while maintaining adequate fillage, thereby increasing operations efficiency and prolonging pump life. Within a thermal environment, enhanced automation provides the additional advantage of steam break through mitigation. The mitigation improves pump efficiency and prevents pump gas lock. This algorithm provided a unique advantage within this thermal operation by adapting to varying viscosities impacting inflow throughout the production phase. Thermal CSS requires continuous monitoring and rapid reaction time to adapt to the dynamic conditions inherent to the CSS operation. The BLADE project has demonstrated that utilization of carefully designed logic in conjunction with robust field steaming strategy, not only improved field recovery but also significantly reduced manpower demand by 20% and decreased the total EOR cost.

Enhanced Oil Recovery (EOR) methods are inherently dynamic and challenging. Thermal recovery presents a unique set of challenges which Petroleum Development Oman (PDO) has managed to successfully mitigate, or at least minimize, potential adverse impact. At the "A" East Field the development is currently dominated by Cyclic Steam Stimulation (CSS). This is a well established thermal recovery method and typically is a precursor for Steam Drive (SD) in many thermal fields. Successful CSS operation provides effective reservoir pre-conditioning for subsequent SD operation. If CSS is compromised, SD will not yield the anticipated optimum volumes. This paper will therefore focus on steam breakthrough mitigation in thermal operations and various approaches to manage this inevitable risk. Steam breakthrough (SBT) occurs when steam finds its way from an injector through the reservoir and into an adjacent producing well. Steam breakthrough is an expected phenomenon; however, if it occurs prematurely in a thick vertical reservoir, it can lead to poor sweep which, if unmitigated, will compromise ultimate recovery output by increasing Steam to Oil Ratios (SORs). Inadequate sweep may be exacerbated by operational conditions, well type selection (vertical vs. horizontal wells), or geological and petrophysical characteristics (well spacing, high permeabilitystreaks,etc.). Instrumentation and active surveillance methods are critical components in identifying indicators of compromised sweep. Surveillance methods, including temperature logging and pressure data, are essential for performance evaluation. Early signs of impending steam breakthrough can be identified by producer well hydraulic support from nearby injectors, followed by a rise in temperature. Various operational and mechanical methods were utilized to minimize sweep inefficiency and creative well management concepts were employed including Group CSS (GCSS), where a set of communicating wells are operated as if they are one CSS set. Steam breakthrough is a common concern in most thermal operations. Identifying the best approach to mitigate or minimize the associated adverse impact requires an understanding of well dynamics and behavior. This allows the most suitable and cost effective measures to be implemented. Within "A" East Field, most wells experiencing SBT improved once mitigations were introduced. For example, pump performance and efficiency improved after implementing SBT management controls. A decision tree hierarchy was key in establishing effective and economic decisions based on actual well behavior. The optimal mitigation choice strikes a balance between cost and operational efficiency. CSS wells pose unique operational challenges in deep thick reservoirs compared to a more typical thin, shallow reservoir. This paper describes the risk and also lays out mitigation steps to minimize steam breakthrough impact on production and overall project economics.

Thermal field development often requires trials or pilots to unlock additional oil recovery. "A" East (ALE) is a thermal EOR oil development project located on the Eastern Flank of the South Oman Salt Basin. An initial/ongoing development phase in the upper part of the reservoir primarily consists of Cyclic Steam Stimulation (CSS) followed by steam drive. Aiming to increase the field's total ultimate recovery, the next development phase was conceived to target the more viscous oil (up to 200,000 cP) in deeper zones, deemed too challenging in the first phase. Many concepts were evaluated, however "Cross Top Down Steam Drive" (X-TDSD) was ranked as the most favorable option to address the development uncertainties. Similar to the Steam Assisted Gravity Drainage (SAGD), the injection wells will be positioned above the production wells. However unlike SAGD, the injectors will be placed perpendicular (cross) to the producers. Additionally, the XTDSD will assess the approach of utilizing a combination of steam flooding at the top, using vertical wells, and a gravity drainage process at the bottom using horizontal wells. The X-TDSD trial scope includes the drilling and completion of two horizontal injectors, three horizontal producers, and three vertical observation wells. These will be accommodated within the existing infrastructure. The acceleration of the three observation wells reduced some of the main uncertainties prior to executing the horizontal wells. These included structural geology, stratigraphy, and grain size analysis for sand control requirements. The success of the X-TDSD trial depends not only on reservoir properties, but also on the well and reservoir operating strategy. A clear plan for operating parameters and real-time surveillance were incorporated into the project development plan. Permanent production and injection monitoring are included, to facilitate systematic adjustment of the well parameters. This aims to optimize steam chamber development during the pilot's operating life. Flexibility was incorporated in the wells and facility design to accommodate the six planned modes of operation, as described later. This paper will focus on the design details, which required integrated input from several disciplines.

Thermal recovery is becoming a main stream enhanced recovery method for heavy oil with unique challenges. The extreme nature of thermal recovery requires flexible and creative approach to address the unique challenges. One of the accepted recovery thermal methods is Cyclic Steam Stimulation (CSS). The thermal cycle starts with injection phase followed by soaking, and finally, production phase. Conversion from injection phase to production phase is considered a significant operational risk in addition to typical risks associated with oil production operations. The additional risk during the conversion to production from an injection cycle is due to the significant energy placement in the reservoir during steaming. If not controlled, high energy hydrocarbon fluids flowing back to surface can lead to loss of containment and harm to life or the environment. Beam Pumps have been used predominantly in conjunction with insert down-hole pump and sucker rods. During injection phase, the well is operated as an injector without pumps or rods, and when the time comes to convert to a producer, rods and insert pumps are reinstalled. This conversion step from injector to producer is highest risk in the CSS well operation cycle. After the injection cycle is completed, a significant energy is placed into the reservoir, the well is shut in for soaking period which is 1-3 days. Free flow is required after the shut in period to depressurize the well. Depressurization period extends in some cases to many weeks and would require killing the well where it's common that a well would not die off just by depressurization alone resulting in significant wait time. The amount of flow back and energy stored in the well is directly proportional to steam injection pressure and duration. In many cases where well still retain some energy and pressure is still high for intervention, due to free flowing not subsiding, killing the well is utilized. Well killing procedures pose another set of challenges such as; pump start up challenges due to viscosity reduction, cost for brine mix and wrong pressure estimation leading to prolong interventions. The challenges in CSS opened an opportunity for innovation where thermal wells could be attended for conversion with minimum rods taken out or rods added back in under high temperature and pressure. The new concept is a combination of dual rod Blow Out Preventer (BOP) and stripper seals set in series. A trial in November 2017 was conducted with positive results where the advantages of this innovation were clearly demonstrated. This paper is a summary of the design approach and the successful trial proving the concept.

As primary recovery declines in a heavy oil field an EOR process becomes an essential long term field development mechanism. There are several EOR methods to select from and thermal EOR is gaining momentum as experience and successful developments are becoming wide spread. Monitoring and surveillance has also improved in part due to technology advancements to operate in extreme thermal conditions. There is a need to carefully approach a thermal development and this presentation will discuss the staged approach taken to better facilitate the following thermal development. It is believed that a heavy oil field in South Oman has a tar Mat like base (permeability barrier in the oil column) where water in the aquifer is shielded from the producible layer. Analysis work done on viscosity indicated that primary production can be achieved and thermal phase should follow. This was confirmed by trials done on selected wells. Leading to the implementation of a "staged approach" starting with cold recovery, followed by cyclic steam stimulation and then steam drive. The improved plan required a change in surface pipe lines and facility and also well completion designs to accommodate as much as possible both modes of recovery (cold and thermal). This presentation will go over the staged approach for the thermal development and the challenges experienced in getting there.