In this consistently low oil price environment, where infill drilling and new field developments struggle to meet economic metrics, production optimization continues to be a focus and driver for the industry. Currently, waterflooding contributes significantly to global oil production and is one of the main non-thermal techniques that can be applied to increase pool recovery. Although proper reservoir management of assets under Waterflood (WF) is critical to reaching the highest recovery factor (RF) possible, it is difficult to achieve and maintain given the inherent dynamic nature of the production mechanism. Further, to achieve optimum reservoir management while providing the opportunity to leverage alternative enhanced oil recovery (EOR) technology, the existing subsurface and surface infrastructure should be fully optimized. By optimizing the subsurface and surface infrastructure in parallel with achieving optimum reservoir management it will result in higher capital efficiency while improving key economic metrics such as operating expenditure (Opex), reserve replacement ratio, depreciation depletion & amortization (DD&A), and overall earnings. Given the existing challenges that include reservoir conformance problems, lack of reservoir energy, excess fluid production, wellbore and pipeline integrity issues, and infrastructure constraints, how to fully optimize the current infrastructure while achieving optimum reservoir management in parallel is the main question and challenge. Husky Energy’s medium oil reservoir management strategy has been highly successful in reinforcing WF as a sustainable long-term recovery method. This paper will present a practical workflow to tackle the challenges highlighted by using a systematic reservoir and production engineering approach with minimum additional capital expenditure (Capex). First, a robust framework was developed to answer three main questions: "What is happening?", "Why is it happening?" and "How can it be improved?". Then, a comprehensive dynamic surveillance methodology, consisting of both numerical and analytical techniques and a 10-step workflow for optimizing a WF project, is discussed. This is followed by the results achieved by employing this strategy in three of Husky’s WF fields; the Wainwright Sparky, Wildmere Lloydminster and Marsden-Manitou Sparky pools located in the Lloydminster oil block. The positive impact that this reservoir management process has had on all key financial metrics will be discussed. As an example, since the beginning of the optimization initiative the Wainwright and Wildmere pool production has increased 21% and 23% respectively, while the Opex has decreased by 33% and 42%, respectively. Further, since implementing a similar strategy in 2016 at the Marsden-Manitou WF, its production has increased by 30% and its Opex has decreased by more than 18%. Finally, this paper will present a WF protocol check list that has been developed as a guideline for engineers who need to optimize pool performance even in a capital constrained environment.

This paper focuses on the strain based design and field application of thermal well casing for cyclic steam stimulation process. The heavy oil is a main field of China petroleum industry, where the cyclic steam stimulation process has been widely used and playing the dominating role in production. Generally the casing damage rate is 15-30% under this process, which has resulted in a large economic cost. The high damage rate is mainly caused by the current strength design method, where both the room and elevated yield strength were considered not beyond anticipated field thermal stress. In fact the casing material will serve in cyclic thermal elastic-plastic deformation state and the single yield strength is not sufficient for long term thermal stimulation process. This paper presented a new strain based design method for thermal casing string. New material parameters were proposed to build the safety evaluation principle throughout the service life. For thermal casing the material plasticly deforming limit, called as allowable strain, is determined by the homogeneous deforming capacity. For design strain, the material creep rate equation is introduced to evaluate the accumulative elevated strain in long term service together with initial install strain, thermal strain and soil strain. When the design strain is not more than the allowable strain the casing material will safely serve throughout the whole life. In addition the strain fatigue limit is measured to evaluate the material safety for thermal cycle life. According to the factual field engineering environment the gas tight thread joint was adopted to prevent steam leak which otherwise will cause a large transversal stress between different formations and result in slip deformation of casing string. Before the engineering operation the full scale test procedure was proposed and finished to evaluate the string integrity in multiple thermal cycles. From 2011, this method was used in Xinjiang oil field for eight wells for more than 14 steam cycles and all the experiment wells served well without any damage. Several wells were cyclic measured through multi arms inspector and the data showed that all the casing deformation located in controlled scope except that only one has obvious deformation because poorer cementing quality. The field practice has showed that the new method has better fitness for thermal wells.

Inflow control devices (ICDs) have been extensively used in horizontal wells for conventional oil and gas production in order to prevent early water break through or gas coning. The benefits associated with this technology have been studied with reservoir simulation and validated with field experience. Some of the benefits associated with ICDs that have been described in the literature are: easier well clean out during start up because the ICDs allow application of higher drawdown to poorly performing sections of the reservoir, higher recovery factor caused by delayed water break through or gas coning, uniform production contribution of the horizontal section, and better sand control by limiting the fluid rate per joint. In theory, similar benefits can be achieved using ICDs in SAGD applications. In this case steam break through instead of gas coning could be prevented. If live steam production is mechanically controlled by the ICDs, bitumen from the colder sections of the production well can be produced by applying a higher drawdown. In this way the total bitumen production should be increased while steam oil ratio (SOR) is reduced. Nevertheless, the available drawdown between SAGD well pairs is very limited and the conventional design approach consisting of uniform flow along the horizontal section is not applicable. To design an ICD completion trial at the MacKay River SAGD Project, Brion Energy has conducted studies involving theoretical analysis, segmented well simulation, technology evaluation, and equipment selection. The results of these studies indicate that higher cumulative production with lower SOR can be achieved when the ICDs are installed in bitumen production wells where the reservoir exhibits significant heterogeneities. However, the hot spots in the well have to be produced at zero wellbore sub-cool in order to generate a differential pressure capable of bringing colder sections of the well into production. The study also suggests that a further reduction in SOR can be achieved when the ICDs are also installed in the steam injection wells.

In situ combustion (ISC) is one of the improve recovery methods with a high potential to increase the recovery of heavy crude oil. Although we mentioned this major advantage, this process has not being used in Colombia yet. This fact due mainly to the complexity of the involved phenomenon, therefore a field project must be design after extended laboratory investigation. Experimental tests in combustion tubes made through the main conditions in the oilfield have being the process' evaluation tool with the highest acceptance. These tests show the speed and stability of the combustion front and the obtained results from the production's analysis of fluids, mainly the ones of the exhaust gases. It is possible to calculate the basic combustion parameters by using: combustible consumption, required air, air- combustible relation, hydrogen- carbon atomic, and oxygen use. The parameters mentioned before let, trough different scaling analytic methods to evaluate the technical and economic viability of the process in the field. In this work was developed a computational tool that allow calculating the design parameters through different scaling analytic methods Nelson & McNeil, Gates & Ramey y Moore et al). Comparing the results got from the different described methods, when scaling two tests in a combustion tube, they show similar numbers. Taking into account that Nelson and McNeil's method is the most useful one due to the oilfield characteristic, it was made a sensitivity of operational parameters and the result permitted to study the relation between the oilfield operational variables

The integration of horizontal wells and thermal oil recovery methods, such as Steam Assisted Gravity Drainage (SAGD), has enabled the economic exploitation of extra-heavy oil resources, mainly in Canada. The use of passive outflow control devices (OCDs) in SAGD wells adds steam injection points along the horizontal wellbore influencing steam placement and chamber growth; thus, potentially reducing the steam-to-oil ratio (SOR), productivity uncertainty and accelerating production. For designing OCD installations in SAGD, we need to address two main aspects. Firstly, the interface between horizontal wellbore hydraulics and reservoir injectivity that allows determining the optimum number and location of the steam injection points. Secondly, the design of the OCD itself, which involves selecting and configuring the device with a hydraulic performance that is fit for purpose. For this study we will focus specifically on straight-orifice choke passive OCDs. This paper presents a comprehensive design methodology for tubing deployed passive OCDs in SAGD. The completion design is carried out with a steady-state model of the injection well using a commercial thermal wellbore simulator. The field performance evaluation of tubing deployed passive OCDs is critical for verifying the effectiveness of the design methodology and the hydraulic performance of the devices under real field conditions. The field evaluation is done by history matching the injection pressure vs. steam rate data with a model developed in the thermal wellbore simulator. A dynamic pressure gradient (under flowing conditions) in the injection string carrying the OCDs is obtained with a temperature log, taken with fiber optic technology, where the temperature data is converted to pressure by virtue of the properties of saturated steam. This approach is new for the SAGD industry. The OCDs hydraulic field performance was successfully matched with the simulated model, which indicates the effectiveness of the design methodology, the field performance evaluation techniques and the effectiveness of the OCDs in delivering the desired amount of steam at each location.

When developing properties using the steam assisted gravity drainage (SAGD) process, the lateral spacing between horizontal well pair spacing is extensively evaluated during well pad design to optimize resource recovery and economics. However, constraints associated with central processing facilities (CPF) are often not incorporated into the evaluation. With constrained steam supply and fluid processing capacity, the accelerated production that should accompany a reduced well pair spacing scenario may not be realized. In this paper, the economics of developing a SAGD property using 50m, 85m, 100m and 125m well pair spacing are compared within Suncor's MacKay River property. A production development planning tool is used to tie the individual well production profiles to a constrained CPF. While higher oil production rates, a cumulative steam-oil ratio (CSOR) reduction, and slight increase in oil recovery are observed at the well pad level in the 50m well pair spacing scenario, no accelerated oil production is achieved at the CPF level as steam supply and fluid processing capacities are constrained. With larger well pair spacing, the addition of more new pads on an accelerated schedule serves to maximize the CPF capacity utilization and oil production. Hence, the overall oil production at the CPF level is practically the same regardless of well pair spacing. With the areas evaluated in this study, the economics of the 85m, 100m and 125m cases are very close, with the optimum achieved at 100m well pair spacing. The 50m well pair spacing scenario produces the worst economic result as the tighter spacing case requires incremental capital for additional wells to achieve the same resource recovery. Without the accelerated production at the CPF level due to facility constraints or appreciable incremental oil recovery and CSOR reduction overall, there is no increased revenue to offset the increased capital outlay.

Physical modeling of heavy oil recovery processes is a critical step in evaluating their technical feasibility. Results from physical modeling studies, in conjunction with simulation and analytical modeling, are key to technically justifying field trials and pilots. Proper scaling of reservoir model dimensions, reservoir properties and energy boundary conditions, operating condition monitoring and control, and production data analysis are very important aspects of physical model design and operation for evaluating the performance of a heavy oil recovery process. This paper describes physical modeling and performance evaluation of the Solvent-Assisted SAGD (SA-SAGD) process applied to Athabasca oil sand reservoirs with focus on process optimization under low operating pressure condition. The paper presents the design features of the physical model used for testing that ensures reliability and reproducibility of the experimental results. The results of laboratory testing are shown with emphasis on demonstrating the reliability and reproducibility of the test results.

The Suffield Caen reservoir contains 17°API heavy oil and the pool has been under waterflooding since 1996 with water cut of 96%. Primary and secondary oil recovery is 15 – 20% of OOIP. A major problem encountered in waterflood was poor sweep efficiency and high water cut caused by high water/oil mobility ratio, as water quickly broke through the reservoir owing to fingering effects. It is known that sweep efficiency during waterflood can be improved significantly by increasing the viscosity of injected water by use of polymer solution, thus generating a more favorable mobility ratio and enhancing oil recovery. The results of reservoir simulation studies suggested that polymer flood would achieve incremental recovery factor of 7 – 12%, and coreflood results indicated that 29 –32% of incremental recovery is achievable by 0.5 pore volume (PV) of polymer injection. Core floods including polymer, surfactant/polymer(S/P) and alkali/surfactant/polymer (A/S/P) were conducted through lab experiments and eventually polymer flood was selected as a pilot project to improve oil recovery for the Caen reservoir on the basis of polymer, S/P and A/S/P core flood results and project economic evaluation. Polymer injection started in the reservoir 15 months ago and a very positive response has been seen as oil cut has increased to 10% from 5% and oil production rose to 600 bbl/d from 400 bbl/d. Therefore, the polymer flood pilot project is continually implemented and the polymer flood is planned to extend to similar reservoirs in the Suffield area. There is a large amount of conventional heavy oil resaves in the West Canada Basin, so far the primary recovery factor is only 10%, there is a big potential to enhance oil recovery by polymer flood. This polymer flood pilot project provides valuable experiences and guidance to field application.