The paper describes the theory of modelling waterflood induced fractures and the features which distinguish this process from conventional hydraulic fraCturing. The mechanisms which are described in detail and illustrated by examples include 2-dimensional leak-oft', the effect of previous injection, relative permeability and thermal effects, and pre-existing propped or acid fractures. All of these features have been found necessary for accurate matching of complex injection history of North Sea wells.

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.

This paper describes a study of the potential of a tight reservoir zone for disposal of brine generated in salt cavern leaching operations. The study included field injection testing, numerical analysis using uncoupled and coupled reservoir, geomechanical and fracturing modeling, laboratory work and design of a field injection monitoring program. It was shown that a surprising brine disposal capacity exists in the tight ͑0.03 md͒ Oriskany target formation. Initial screening was followed by carefully designed injection testing, laboratory work and subsequent evaluation with the aid of detailed coupled fracture and reservoir numerical models, and numerical well test analysis. Low initial estimates of brine disposal capacity were increased significantly by incorporating more sophisticated, coupled reservoir and geomechanical numerical models. The models, which account for stress dependent porosity and permeability and fracture propagation, were calibrated to laboratory and field test data. Using these models, an excellent match of the injection data was obtained, and predictions of injectivity were made under various project scenarios. The coupled model has been also used to design the monitoring program for the first phase of the injection operations.

The Garzan B and C Pools, located in southeast-central Turkey (Figure 1), were studied for enhanced oil recovery (EOR) potential. A review of this study is presented in this paper. The study consisted of a review of geological and reservoir engineering data followed by black oil reservoir simulation history matching of primary and waterflood depletion phases over a 27 year period. Selected pattern elements were then period. Selected pattern elements were then subjected to various EOR processes using compositional and thermal simulation models. The optimal EOR process, selected on the basis of technical and economic criteria, was extrapolated to full field scale and compared to optimized waterflood simulation predictions. The study predicts that immiscible Dodan gas (mainly CO2) injection on 54 acre [21.9 ha] inverted 9-spot patterns will provide enough recovery and economic benefits over optimized waterflooding to warrant proceeding with a pilot gas injection scheme. STUDY OBJECTIVES The study objectives included full field history matching for both the Garzan B and C Pools followed by EOR screening for immiscible gas injection, steam, and in-situ combustion potential. For brevity, this paper will refer only to the B Pool where appropriate, since the Garzan B and C Pools are very similar. ROCK AND FLUID PROPERTIES Geology The structure is a double plunging anticline bordered by a major reverse fault extending along the southern flank (Figure 2). To the north the pools are defined by a lateral thinning of the pools are defined by a lateral thinning of the porous limestone interval mainly as the porous limestone interval mainly as the depositional facies wedge out. These pools are heterogeneous in nature and are in limited hydrocarbon communication through the deepest of four defined geological layers (Figure 3). The age of the Garzan formation is cretaceous, comprised of carbonates of a rudist build-up complex. Fluids The subject pools contain 24 degree API [0.91 g/cm3] oil with a reservoir viscosity of 6.75 cp [6.75 mPa.s]. The pools were initially highly undersaturated. Table 1 lists basic reservoir data for Garzan B and C Pools. FIELD DEVELOPMENT HISTORY The Garzan B Pool was discovered in 1951 followed by limited development until the completion in 1956 of a field-to-refinery oil pipeline. Primary Depletion Primary Depletion From 1956 to 1960, after production of 1.3 percent of the original oil-in-place (OOIP), the average B pool pressure had decreased to 725 psi [5,000 kpa] pool pressure had decreased to 725 psi [5,000 kpa] from its original value of 1405 psi [9,688 kpa]. Flowing bottomhole pressures at some wells were below the bubble point of 713 psi [4,916 kpa]. P. 521