Reservoir uncertainties, increasing water cut, vertical lift performance, well integrity issue along with decline in production are some of the typical challenges of a mature asset. These coupled with ageing facilities and lower production efficiencies are key issues that an operator faces while operating any mature asset. Production decline from a mature field cannot be fully arrested. However, it can be reasonably controlled by using real-time optimisation techniques. This paper deliberates on how BG India has been able to address these issues successfully while operating mature assets in Mumbai offshore region. This paper presents how real-time production data, performance monitoring and application of innovative techniques can help in adding extra barrels to production. In the past few years, oil industry has been moving towards Real-Time Optimisation (RTO). However, to achieve optimal benefit from RTO, a new implementation approach-based on People Process Technology (PPT) framework has also been proposed in this paper. This paper recommends innovative practices like integrating non-technical disciplines, for e.g. Logistics, Planning, Contracts and Procurement etc into core production enhancement team. It also presents techniques to setup required processes to complement the traditional way of production opportunity and loss management. Furthermore, an outline has been presented on how to select the suitable technologies during the state-of-the-art Real-Time Optimisation Centre (RTOC) set up for any Oil and Gas asset. Several case studies have also been included in the paper to highlight the benefits from a RTOC based on PPT framework to manage the typical challenges of a mature asset. Using this approach, BG India has been able to reduce decline in production while achieving high production efficiency of more than 90 percent in the last three years for its fields in Mumbai offshore region. Going forward, more and more assets worldwide are likely to enter into the mature stage of lifecycle. Methods suggested in this paper provide a unique approach to implement a strategy to shift production management culture from reactive to proactive domain.
Pipelines are usually considered the most effective and economical means for transporting fluids from satellite wellhead platforms to central processing platforms. However, the actual production from the reservoir during field life could be different than expected due to associated uncertainties in various production phases. As a result, pipeline flow assurance issues are the most common challenges faced in mid-to-late life phase of an oil field. In mature oil fields, water cut increases with time. The total fluid flow through a pipeline may also increase due to better reservoir deliverability than expected, infill wells opportunity, workovers, zone change, gas lift deepening, etc. An increase in total fluid content causes a higher frictional pressure drop in the pipeline and increases the backpressure on flowing wells. This detrimentally affects well deliverability at declining reservoir pressure in mature fields. A traditional approach to reduce backpressure on flowing wells is to flow the selective wells in a satellite platform. In short, the risk of increased backpressure can prevent the opening of additional available wells, thereby significantly limiting the production from a satellite platform. Another approach is to lay a new pipeline, but this is capital-intensive and time-consuming option that is often uneconomical in the late-life phase of an oil field. This paper explores a chemical route, the application of drag-reducing agent (DRA), to address the issue of high frictional pressure drops in pipelines. DRAs have traditionally been used in pipelines handling fluid with low-to-moderate water cuts (<50%). However, their application in high water situations (fluid having water cut higher than 80%) have been rare and met with limited success. A trial of a new DRA was carried out in a mature oil field in the Mumbai offshore region. A pipeline handling high water cut fluid (>80%) was selected for this application. This DRA is a long-chain polymer that attaches to water molecules, thereby streamlining the flow. The DRA reduces the frictional pressure by acting as a buffer along the pipe wall to decrease the amount of energy lost in turbulent flow. Application of this DRA in high water cut pipeline lowers the pressure drop with a given fluid flow, enabling the operator to flow additional wells into the same pipeline. This paper discusses the rationale behind the identification of a problem using pipeline flow modeling (using water cut, production rates) and the selection of the appropriate chemical (considering water chemistry), along with the results from a successful field trial. In the future, many mature oil fields will deal with issues like higher water cut fluid flow in a smaller diameter pipeline. In these situations, a drag-reducing chemical can significantly improve overall recovery.
Calcite scaling is a major production challenge in many mature oil fields. One of the most effective manners to control calcite scaling losses is to predict the scaling behavior in the wells using thermodynamic models and then use prediction results to build an operational program to control scaling in the field using a combination of effective acid washes and scale inhibitor (SI) injection. This paper presents a case study from a mature oil field and details the operational facets of scale prediction and control program. It describes both operational challenges as well as cost optimization involved in program implementation in the field. There are three major aspects which are discussed in this paper. First part deals with selection of right scale inhibition chemical for a field. It details laboratory experiment that was used to select the most appropriate chemical for the field. Also, this section describes the hardware infrastructure that should be in place to ensure effective implementation. Next section deals with the trial of chemicals, selected from lab analysis, in actual field conditions. Impact of scale inhibitor in controlling scaling within the tubing and flowarm of the wells is discussed. Secondly, benchmarking of new scale inhibitor chemical performance against the existing chemical is also presented in this section. This formed the technical basis for change in existing scale inhibitor and going for full fledged implementation in the field. Final part of the paper details field-wide implementation of scale inhibitor injection and chemical performance monitoring program. Critical parameters for chemical performance monitoring and field data on chemical dosage optimization using these critical parameters are presented. This section also presents several case studies showcasing impact of scale inhibitor injection on the well performance. This scale management approach has not only helped in terms of reducing production losses but also assisted in improving safety performance. Field data, highlighting the impact of scale inhibitor in significantly reducing the scaling in the wells, is shared in this paper. Post implementation of this program, asset has been able to reduce its scaling related production losses significantly (~90% reduction in less than 2 years). Once an oil field enters decline phase of its life cycle, reservoir pressure drops and water cut increases – conditions which favor high scaling behavior in the wells. Thus, scaling related losses presents a serious challenge in controlling production decline in a mature oil field. By adopting the operational practices shared in this paper, many mature oil field can benefit by reducing scaling related losses.
Declining reservoir pressure, increasing water cuts along with dwindling well counts pose a serious challenge to any mature oil and gas field in sustaining production. In low oil price scenarios, enhancing production using conventional approaches like workover and interventions becomes challenging due to associated costs. This provided an opportunity to look for alternate approaches that are cost-effective and would help to manage these issues on a continuous basis. This paper presents techniques for augmenting productivity of well stock by mitigating a range of issues causing production losses using cost effective, easy to implement chemical based techniques. These techniques have helped the asset to significantly arrest its production decline in the late life phase. This paper details the approach for identification of issues, selection and field implementation of right chemicals and the benefits that were realized from such applications. Case studies from BG Exploration and Production India Limited (BGEPIL) operated field in Mumbai offshore region are incorporated in this paper to highlight the effectiveness of chemical based approach in mitigating losses right from reservoir to processing platform. Some of the production issues in this mature field which have been successfully resolved using chemical based techniques are: Reservoir:○Loss of well stock due to Downhole emulsion issueWell:○Calcite Scaling deposition in wells and topsides○Liquid loading of High Gas Liquid Ratio wellsPipelines:○Back Pressure on wells due to Pipeline size limitationProcessing Facilities:○Deterioration in Heat Exchanger performance due to fouling Process adopted includes field data acquisition, analysis using real time state-of-the-art network and process models to identify the root cause of these issues. Results from both steady state and transient models were used to select the appropriate chemicals, conduct field trials / implementation and set the success KPI's accordingly. This paper offers a holistic approach on resolving each of the discussed production issues utilizing the best available technology in the market. Trials and implementation of the various chemicals in the field have added a significant value to the asset; both by protecting and enhancing the current production. More than 20% of current field production is directly attributed to these chemical applications and expected to add more share of production in a far more challenging phase of mature asset. The approach discussed here for each of such production issues along with the challenges that were faced during implementation will enable other assets to tackle these problems with a more cost effective and easy to implement solutions especially in low oil price environment.
Calcium carbonate scaling within well tubing and surface piping leads to significant production loss in many oilfields across the world. Scaling tendency of produced fluids increases multi-fold in a mature reservoir with increase in water production and decline in operating pressures. This paper demonstrates the use of modelling to help anticipate scaling issues and convert predictions into operational decisionmaking which has prevented significant value erosion in a mature field. Majority of the efforts in tackling scaling related losses have traditionally been centered on performing scale treatment after observing a significant change in flow parameters. Although this approach delivers value, it is more reactive in nature and becomes challenging to address in a logistically constrained offshore environment. This paper presents a case study on a new proactive framework on Scale Management. This new framework is driven by P2P approach - Prediction to Prevention. Prediction of scale formation tendency in wells was carried out using a thermodynamic model. Once wells with scale formation tendency were identified using thermodynamic model, scale prevention was done by selection and application of scale inhibitor chemical along with progressively reducing number of surgical acid washes. The scaling behavior was compared against the operating conditions of wells and the findings complemented the understanding from thermodynamic simulations. Paper deliberates on the cost optimization while application of this approach so that it remains extremely cost efficient in comparison to traditional approach. It details the evolution of scale management strategy right from project initiation to field maturation spanning across 30 years of production. With periodic reviews of this framework, additional ~10% of available well stock was identified as new wells migrating into scaling envelope over the last one year and added to Scale Inhibitor dosage program. This prevented production losses and well integrity issues in these wells. Wells put on continuous scale inhibitor injection as per recommendations of this approach did not have down-hole safety valve failures, protecting 35% of field oil production volume and ensuring safer operations demonstrating strong business value. Overall, application of this P2P framework has helped asset to reduce yearly scaling related losses by more than 90%.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.