This page provides several reservoir management case studies that illustrate carbonate reservoirs in which waterflooding and miscible gas injection techniques have been implemented. This field produces primarily from a Jurassic-age limestone-dolomite section that has a simple plunging anticline structure. The updip trap is formed by a combination of facies change from dolomite to dense limestone and a bounding fault. The formation is layered and has been divided into 18 correlative zones. When production began, the reservoir pressure declined rapidly under a fluid-expansion drive.
Carbonate sediments are commonly formed in shallow, warm oceans either by direct precipitation out of seawater or by biological extraction of calcium carbonate from seawater to form skeletal material. The result is sediment composed of particles with a wide range of sizes and shapes mixed together to form a multitude of depositional textures. The sediment may be bound together by encrusting organisms or, more commonly, deposited as loose sediment subject to transport by ocean currents. A basic overview of carbonate-reservoir model construction was presented by Lucia, and much of what is presented herein is taken from that book. Depositional textures are described using a classification developed by Dunham. The Dunham classification divides carbonates into organically bound and loose sediments (see Figure 1).
Designing an acid-fracturing treatment is similar to designing a fracturing treatment with a propping agent. Williams, et al. presents a thorough explanation of the fundamentals concerning acid fracturing. The main difference between acid fracturing and proppant fracturing is the way fracture conductivity is created. In proppant fracturing, a propping agent is used to prop open the fracture after the treatment is completed. In acid fracturing, acid is used to "etch" channels in the rock that comprise the walls of the fracture.
Many aspects of reservoir geology interplay with the immiscible gas/oil displacement process to determine overall recovery efficiency. As with any oil recovery process involving the injection of one fluid to displace oil in the reservoir, the internal geometries of the reservoir interval have a controlling effect on how efficiently the injected fluid displaces the oil from the whole of the reservoir. The stratigraphy of a reservoir is determined primarily by its depositional environment. First and foremost is how layered the reservoir is in terms of both how heterogeneous the various sand intervals are and the scale at which shales or other barriers to vertical flow are interbedded with the sands. Another very important aspect is how continuous the shale intervals are.
Waterflooding involves the use of injected water to displace oil in a reseroir. This process is a method of secondary recovery. Conventional oil recovery involves improving volumetric sweep efficiency via a variety of technologies and practices, including in-fill drilling, multilateral wells, improved reservoir characterization, high resolution reservoir simulation, and advanced monitoring and surveillance. Around 50% of the world's known oil resolves are in carbonate reservoirs. As Primary recovery mechanisms yield low recovery factors and therefore companies seek Secondary or even Tertiary recovery methods.
San Andres and Clearfork are two carbonate reservoir intervals that are present over a considerable area of the Permian Basin in west Texas. These reservoirs (e.g., Wasson, Slaughter, Seminole) contain several billion bbl of approximately 30 API oil. They are very-layered, heterogeneous carbonates and dolomites that have large variation in permeability from layer to layer. Interestingly, because of the complex hydrocarbon-accumulation history of this basin, much of this area has an underlying interval that contains residual oil saturation. Most of these reservoirs were discovered in the late 1930s and the 1940s.
Pathak, Varun (Computer Modelling Group Ltd.) | Hamedi, Yousef (Computer Modelling Group Ltd.) | Martinez, Oscar (Computer Modelling Group Ltd.) | Vermeulen, Stephen (Computer Modelling Group Ltd.) | Kumar, Anjani (Computer Modelling Group Ltd.)
Integrated production systems models are very valuable for predicting the performance of complex systems containing multiple reservoirs and networks. In addition, the value of quantifying uncertainty in reservoirs and production systems is immense as it can build confidence in operational investments. However, traditionally it has been extremely tedious to incorporate uncertainty assessments in the context of integrated production systems modelling. This has been addressed in the current work with the help of a case study.
In the current work, a complex integrated production systems model is presented - from Pre-Salt carbonates reservoir offshore of Brazil. The model includes multiple reservoirs with unique fluid types and complex fluid blending in the production network, multiphase and thermal effects in flowlines and risers, gas separation, gas processing, gas compression, and re-injection for either pressure maintenance or for miscible EOR.
The operational strategies, well placement, and well and network configurations are often based on a single geological realization. With the case study presented in this paper, an integrated way of quantifying geological uncertainty has been presented. A new multi-user, multi-disciplinary tool was used for this study that removed any discontinuities and inconsistencies that typically occur in such projects when multiple standalone tools are used for individual tasks. When quantifying uncertainty on production, the dependence on a single realization was eliminated as uncertain parameters were identified and used for creating robust probabilistic forecasts. Probability distribution curves were generated to represent the uncertainty in overall production from this asset, and the risk associated with operational investments was minimized.
Typically, an end-to-end uncertainty assessment is missing from the traditional Integrated Modelling workflows. With this new approach, the challenge of achieving a truly integrated uncertainty assessment for integrated reservoir and production models has been addressed successfully.
Pola, Jackson (Heriot-Watt University) | Geiger, Sebastian (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Bentley, Mark (Heriot-Watt University) | Maier, Christine (Heriot-Watt University) | Al-Rudaini, Ali (Heriot-Watt University)
We investigate how efficiently oil can be recovered from a carbonate rock during surfactant based enhanced oil recovery (EOR) at the core-scale, particularly when chemical processes change wettability, and analyse how geological heterogeneities, observed at the next larger scale (centimetre to decimetre) impacts the effectiveness of surfactant-based EOR at the inter-well scale.
To quantify how heterogeneity across scales impacts surfactant flooding, we combine laboratory experiments with simulation studies at the core- and inter-well scale. We first analysed a series of surfactant imbibition experiments at different surfactant concentrations (from 0 to 3 wt. %) using reservoir cores from the Wakamuk field, a carbonate reservoir in Indonesia. We then built a 3D simulation model of the laboratory experiment and matched the experimental data to identify the key physical mechanisms (e.g., reduction in interfacial tension (IFT) and wettability alteration) that lead to increased oil recovery. Next, we parametrised the surfactant models using assisted history-matching methods to calibrate the relative permeability and capillary pressure curves as a function of surfactant concentration. These models were then deployed in high-resolution simulations at the inter-well scale. These simulations captured the small-scale geological heterogeneities that are typical for a carbonate reservoir system, e.g., the Shuaiba formation in the Middle East, but are not resolved in field-scale models.
Our core-scale simulations demonstrate a change from co- to counter-current flow in the laboratory experiments and indicate that the resulting increase in oil recovery is due to a combination of IFT reduction, wettability alteration from oil- to water-wet, and capillary pressure restoration; these processes need to be captured adequately at the inter-well scale model. The increase in surfactant concentration above the critical micelle concentration (CMC) (i.e., from 1 to 3 wt. %) triggered the capillary pressure restoration and dominated recovery at the early-time. The changes in relative permeability and capillary curves during the surfactant floods were best modelled using a concentration-based interpolation. There is uncertainty when calibrating surfactant models using laboratory experiments. A key question hence is if geological heterogeneity at the inter-well scale masks these uncertainties.
Results from our high-resolution simulations show that large-scale heterogeneity impacts recovery predictions, but it is the coarsening of the grid, not the upscaling of permeability, that dominates the error in field-scale recovery predictions during surfactant based EOR. Indeed, the error arising from numerical dispersion during grid coarsening can be as large as the error arising when selecting an inaccurately configured surfactant model due to the lack of quality experimental data. Hence appropriate grid refinement, possibly using adaptive grid refinement, needs to be considered when setting up a surfactant based EOR simulation, along with the appropriate configuration of the surfactant model itself.
"Smart water" is needed for effective waterflooding in carbonate reservoirs. A novel water-ionic technology, comprising nanofiltration and reverse-osmosis membrane-based processes, was identified for optimization in this study. The number of offshore facilities employing waterflooding with desalination continues to grow. Currently, more than 50 sulfate removal units are in operation offshore with a total capacity of approximately 8 million BWPD. How Does Low-Sal Water Work?
A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. After a drop in drilling activity in recent years, the Haynesville shale has become a hot area for natural gas production in the US, and companies are looking to bolster their positions in the area. Top US seismic experts say they are keeping a watchful eye on ground shaking in the state as new concerns are raised in neighboring Texas.