Presence of H2S detected in producing wells of North Kuwait sweet waterflooded reservoirs over the last 18 years, gave indications of biogenic souring. In response to this, the Kuwait Oil Company engaged in detailed souring potential assessments of selected reservoirs such as the Raudhatain Mauddud (RAMA), to predict the further generation of H2S and define the required souring mitigation strategy to ensure safe production over the remaining field life.
The souring simulation modelling was conducted on the RAMA subsurface model with support from Shell, using a state of the art souring prediction program. The initial phase of the study consisted in the history match simulation to define the most likely souring mechanism in the field. The forecast considered various scenarios with a range of sensitivities on carbon nutrient and sulphate levels, both in formation and injected water in the field.
The history match simulation results showed a good correlation with most of the producers with available H2S data. The Forecast simulation over the next 15-year period predicts a moderate souring severity for this reservoir, based on the maximum H2S mass flow rate of 90 kg/d and H2S in gas maximum concentration of 85 ppmv at the field level.
This work provides the petroleum Industry further insights into the souring behavior when effluent water is injected in addition to seawater, particularly the effects of additional carbon nutrients fed into the reservoir.
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.
This section features industry photographs submitted by SPE members. Selected pictures will be posted on the website. Be sure to provide your full name, job position, company name, picture location, and a caption for the picture. I don't know how anyone could see a sight like this rig and not marvel at its sheer size, design, in... This picture is of a remote field Reliance Production Optimization operates for a client.
After a long cooling off period, this dry-gas shale play is once again red hot. Downhole annulus pressure is required for any gas lift design. This paper presents several methods of determining annulus pressure at depth and helps determine which method is most appropriate for specific conditions. The agency updated its methodology and production volume estimates to factor increasing production from new, emerging plays as well as older plays that have rebounded thanks to drilling advancements. UK’s first horizontal shale well has yielded positive results after an initial flow test.
This paper describes a coreflooding program performed with sandpacks at different permeabilities, water qualities, and injection conditions. In this paper, a new type of sand-consolidation low-viscous binding material, based on a combination of inorganic and organic components, is presented. This paper presents the first successful application of ceramic sand screens offshore Malaysia. Ceramic sand screens were considered as a remedial sand-control method because of their superior durability and resistance compared with metallic sand screens. This paper proposes a new work flow to simulate water-hammer events, the resulting wellbore failure, and sand production in water injectors.
This paper shows how a new approach to small fields could unlock more than twice the net present value (NPV) of larger conventional fields in Southeast Asia at a similar level of capital expenditure (CAPEX). This paper reviews the efforts to exploit CBM resources in Indonesia, the challenges these efforts have faced, and possible solutions that can make operations more efficient and profitable. This paper presents a literature review to determine the engineering challenges and opportunities presented by CBM production in China. A startup company has created a system to create thousands of offshore development ideas by rapidly putting together components like building blocks, which its founders argue will force design teams to look outside their comfort zone. The industry is evolving to a more factual approach to profitability, with emphasis in modeling the long-term scenarios with detail.
Most underground gas-storage facilities are depleted reservoirs. What makes depleted reservoirs attractive is the presence of existing wells used to produce the reservoir, plus the geologic and engineering knowledge acquired during the development of the field. The state-owned firm is looking within its home country, around Southeast Asia, and to the Americas—including shale—in an effort to maintain its forecast average yearly production of 1.7 million BOE/D over the next 5 years. Industry confidence is on the rise, and so is capital spending, according to DNV’s 2019 annual outlook. In this paper, past gas-cycling operations were examined to identify subsurface implications and effects on operability aspects for the Arun giant gas field offshore Indonesia in the North Sumatra Basin.
This page pulls together technology-focused articles from various departments within JPT. Hydrocarbon processing and treating systems often require large and elaborate surface facilities. When operating in challenging locations, such as deep water or the Arctic, these systems can be expensive. Most underground gas-storage facilities are depleted reservoirs. What makes depleted reservoirs attractive is the presence of existing wells used to produce the reservoir, plus the geologic and engineering knowledge acquired during the development of the field. This paper uses a simulation model to evaluate and compare the thermal efficiency of five different completion design cases during the SAGD circulation phase in the Lloydminster formation in the Lindbergh area in Alberta, Canada. This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. The cost reduction per barrel of oil produced and the extension of sustainable production life by optimization have been two major areas of focus, but the investments in new technologies and recovery-improvement research have not received sufficient attention during the downturn. Machine-learning methods have gained tremendous attention in the last decade. The underlying idea behind machine learning is that computers can identify patterns and learn from data with minimal human intervention. This is not very different from the notion of automatic history matching. This paper discusses studies conducted on two California offshore fields that may be abandoned in the near future. These studies examined the feasibility of repurposing these fields for offshore gas storage by using their reservoir voidage and existing pipeline facilities. This paper investigates novel approaches to sour-gas treatment for use in the Middle East that are outside the common oil and gas market and compares them with traditional techniques. The operator piloted a new well-completion design combining inflow-control valves (ICVs) in the shallow reservoir and inflow-control devices (ICDs) in the deeper reservoir, both deployed in a water-injector well for the first time in the company’s experience. This paper shares experience gained in the Ashalchinskoye heavy-oil field with a two-wellhead SAGD modification.
Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.