ConocoPhillips operates Surmont, which is the first Steam-Assisted Gravity Drainage (SAGD) project to implement Flow Control Devices (FCDs) in producer wells. This study was conducted to evaluate the production performance of different liner completion strategies. The analysis compared well pairs completed with slotted liners (SL) to producers completed with FCDs, both liner deployed (LD-FCD) and tubing deployed (TD-FCD), and investigated the impact of FCDs in injectors. An extensive analysis was conducted using available production and temperature data along the wells. The wells were completed using various fixed-resistance FCD settings, while some wells were completed using variable setting designs. As time went on, several of the slotted liner producer wells were retrofitted with tubing-deployed FCD completions. One of the key objectives of the study was to determine the success rate of tubing-deployed FCDs and their performance relative to liner-deployed FCD wells. Another objective was to evaluate the impact of retrofitting slotted liner SAGD injectors with tubing-deployed FCD completions. In this study, a grading system was established based on the reservoir quality along the well for both injector and producer. For similar graded well pairs, LD-FCDs had better production performance than TD-FCDs. Considering similar graded reservoir quality, FCDs consistently performed better than slotted liners, in both conformance and production acceleration. The production analysis showed that the FCD flow restriction was a major controller of the conformance, but considering the self-choking phenomenon of the reservoir, most FCDs can perform positively in different circumstances. In this study, the self-choking effect of the liquid pool is discussed and explained for different reservoirs and variable subcool. Generally, if erosion is not a factor, FCDs can create a more controlling system than liquid-pool dominant systems. In these cases, both conformance and production acceleration is enhanced if operators yield lower subcools and greater draw-down pressures.

Field experience indicates that primary depletion of tight oil formations, using multistage fractured horizontal wells, commonly recovers only 5 to 10% of OOIP. The impact of various EOR techniques on recovering additional oil from these formations is still not fully understood. This paper investigates the applicability of feasible EOR methods and determines their technical and economic success over the natural depletion process under different well and fracture designs. Additionally, the study investigates the minimum reservoir permeability required for success. To achieve the objectives, both black oil and compositional simulation models were generated for a Western Canadian tight reservoir containing volatile oil. In addition to primary, the EOR recovery processes that were considered include waterflooding, immiscible-N2 and miscible-CO2 gas flooding. Combinations of these techniques, coupled with the effects of various well and fracture design parameters were technically explored, and economically ranked using a comprehensive economic analysis. Furthermore, the optimal case of each process was subjected to sensitivity on matrix permeability to determine the minimum permeability at which these methods can be applicable. In the EOR scenarios evaluated, the highest cumulative oil produced was associated with the closest well and fracture spacing, and longest fracture half length. With a larger well spacing (in the order of 400 m), the wells were found to be too far apart to offer any benefit from any EOR technique. Additionally, the capital expenditure of tight-oil projects is high and therefore greatly influences the economic success. Several scenarios yielded similar NPV values, however, the IRR performances and CAPEX requirements helped further evaluate and rank the scenarios. For the reservoir model used, waterflood was found to be uneconomical at the initial permeability levels investigated (around 0.3 md) and required a minimum permeability threshold (1 mD) to become profitable. The primary recovery mechanisms in waterflooding are pressure maintenance and areal sweep, which were more pronounced in the N 2flood. This was the best recovery technique based on NPV. However, the best recovery technique based on oil recovery was the miscible-CO2 flood. It offered an increase in oil recovery factor from 11% to 23% over the best natural depletion case, which was a result of increased oil mobility by dissolution of CO2. At lower permeability values (down to 0.03 mD) immiscible-N2 flood became the most effective method via pressure maintenance within the drainage area. For even tighter reservoirs (under 0.03mD), natural depletion remained the best option for this reservoir. This paper provides an elaborate workflow for evaluating and optimizing EOR techniques in tight oil formations through an integrated modeling approach. It helps to identify the most technically and economically proficient techniques under different levels of permeability, well spacing and fracture parameters.

Computing hardware and reservoir simulation technologies continue to evolve in order to meet the ever-increasing requirement for improving computational performance and efficiency in the oil and gas industry. These improvements have enabled the simulation of larger and more complex reservoir models. When working with steam assisted gravity drainage (SAGD) operations, determining the optimal steam injection rates and allocation of steam among various multi-well pads is very important, especially given the high cost of steam generation and the current low oil price environment. As SAGD operations mature, steam chambers start to coalesce and interact with each other, forcing producers to face declining oil rates and increasing steam oil ratios (SOR). Operators must work to reduce injection rates on declining wells to maintain a low SOR and free up capacity for newer, more productive wells. Steam injection and allocation between wells and multiple pads then becomes an exercise of optimizing cost, and improving productivity and net present value (NPV). A case study is performed on a full field SAGD model by optimizing steam delivery aided by Artificial Intelligence (AI) and machine learning enabled algorithms for automated numerical tuning, and dynamic gridding technologies. The model contains 15 pads, 96 well pairs (192 wells), 12.6 million active simulation grid blocks, and represents a typical Athabasca formation geology and fluid properties. The proposed steam delivery optimization considers two main scenarios. The first scenario considers the case in which steam generation capacity is limited, and the optimization process intelligently determines the optimal well and pad level steam injection rates dynamically during the life of the project. The second scenario assumes that steam generation availability is not constrained and the field development plan is optimized based on steam required for maximum recovery from the field as fast as possible. A full field optimized development plan is created for the 15 SAGD pads and 96 well pairs. Following the optimization, an increase in NPV and reduction in SOR is achieved for the entire field due to the efficient utilization of total available steam. The optimization study required several full field SAGD simulations to be completed in a practical time period, demonstrating that workflows such as this can be carried out for full field thermal models. These models can also be used to evaluate production responses due to varying operating strategies in the field. This paper presents the optimization of steam allocation for a full field, multi pad SAGD simulation model. It demonstrates that advances in computing and reservoir simulation technology have enabled the simulation of full field models within a reasonable timeframe, allowing engineers to tackle a new class of problems that were previously impractical.

For tight oil reservoirs, primary depletion using multistage hydraulically fractured horizontal wells typically only recovers between 5 to 15% of original oil in place, and can exhibit an exponential decline in production rates within a few months. Various enhanced recovery techniques exist, which offer great potential to increase the recovery in conventional reservoirs, however their feasibility within tight formations is not proven. This paper investigates the applicability of several different recovery techniques using a simulation-integrated workflow to both optimize the hydraulic fracture and well configuration design, and determine under which conditions these EOR methods are feasible. In addition to natural depletion, the EOR techniques investigated included immiscible and miscible gas flood and a cyclic Huff n Puff process. Using a simulation model representative of the Elm Coulee reservoir in the Bakken formation, a net present value optimization was performed with comprehensive economic analysis. Optimal operating constraints, fracture design and well configurations were found for each of the techniques investigated. Upon completion of the optimization, each optimal case was subjected to a sensitivity analysis on geological and economic parameters which cover the expected range of the Middle Bakken formation within the Elm Coulee region. Based on this uncertainty, a greater confidence can be achieved in each of the techniques as well as their versatility. From the simulation study, it was discovered that the optimal configuration was different for each of the recovery techniques evaluated. For natural depletion and immiscible flooding, the optimal well spacing was 400m combined with the largest fracture spacing of 125m. Conversely, the miscible flooding method achieved optimal NPV values at the closest well spacing. The cyclic process, which used CO2 for the injected fluid, produced its optimal NPV at a closer fracture spacing when compared to the other 3 methods. Additionally, the Huff n Puff process required further optimization on cycle time to achieve the ideal conditions. The uncertainty analyses performed showed that for each of these recovery techniques the results varied significantly depending on the combination of reservoir, hydraulic fracture design and operating input parameters. Economically, the oil price was the most influential parameter, while geologically the connate water saturation and formation thickness carried the greatest impact. A change in conditions could greatly influence the application of the recovery techniques and possibly yield different optimum configurations. This paper provides an extensive workflow for optimizing EOR techniques and insight into their applicability in tight oil formations. It also demonstrates the importance of understanding the geological parameters prior to determining the ideal recovery technique and corresponding well configuration.

Steam Assisted Gravity Drainage (SAGD) production is a challenging environment where the economics are driven by optimization of the steam injection and oil production. An accurate metering system coupled with downhole pump information is required as is the reduction in physical intervention and operating expenditures. Suncor’s Firebag team engaged themselves in this challenging endeavor over the last 4 years to build a strategy using multiphase flowmeter (MPFM) to (1) provide a compact and versatile solution for new wells, (2) comply with regulations, and (3) validate the metering performances of the MPFM against the conventional separator. The goal of this paper is to address the learnings and challenges faced in the MPFM deployment under these high temperature and harsh line conditions. This knowledge sharing is expected to serve as a guideline for future users of this MPFM technology in SAGD applications particularly with Cold Weather Operations, Multiphase Sampling and High H2S environment, also considering Pressure-Volume-Temperature (PVT) Modeling. From a practical point of view, the qualification, application and benefits of MPFMs in field conditions will be highlighted versus the conventional solution. A particular focus will be placed on the production optimization and reservoir management. Additionally, the synergy between the downhole pump information and instantaneous MPFM flow rate measurements will be reviewed along with the positive impact on the production optimization. The benefit of the MPFM accuracy and continuous measurement is expected to improve the allocation factors applied to all wells and pads.