The objective of this paper is to explore the benefits of using the Interactive Epoch-Era Analysis (IEEA) methodology for evaluating architectural changes in a trade space exploration study. In this paper a subsea tieback offshore Brazil will be used as reference case to investigate this premise from a full field development perspective.
An automated concept exploration tool is employed. It applies meta-heuristics to generate different offshore facilities concepts with varying building blocks. The interaction between reservoir behavior and facilities design is accounted for, meaning pressure and temperature losses throughout the system are taken into account in each concept differently. These concepts are ranked in terms of economic performance indicators (NPV, IRR, etc.), and each run with a given set of boundary conditions covers what is called an Epoch. This process is iterated for the whole life of field with a set of different boundary conditions, such as commercial aspects ($/bbl, $/MMBtu, market demand) and/or technological maturity aspects (TRL, novel technological concepts), generating what is called an Era. The whole data set is then evaluated in an interactive platform thru the Humans-In-the-Loop (HIL) process.
Model Based Systems Engineering (MBSE) is being employed successfully in other engineering fields outside the O&G context such as the aerospace and automotive industries. While digital tools have been identified as a potential key contributor to the future of O&G performance enhancement and further cost reductions, that is yet to be shown. This work intends to provide backing for that argument in one of the potential applications during early concept exploration phases by showing that quick high value assessments following an MBSE approach may be carried out, once significant effort has been put into proper development, verification and validation (V&V) of such digital tools.
While integrated models for asset development have long been a subject of interest for O&G operators, the application of Systems Engineering concepts to it has not yet been thoroughly explored. Systems Engineering provides a rigorous and proven method of dealing with complex systems that is highly applicable to offshore field developments. MBSE is the current State of the Art for capital intensive projects such as space exploration spacecrafts and rovers. Learning from these successful use cases and applying these methodologies in the development of digital technologies may provide a new set of tools in the belt of O&G operators Facilities Engineers and alike. The study case presented shows MBSE’s capability of capturing intrinsic non-linearities and specificities of each O&G field/location while ensuring project wide functional requirements are successfully met.
Yonebayashi, Hideharu (INPEX CORPORATION) | Iwama, Hiroki (INPEX CORPORATION) | Takabayashi, Katsumo (INPEX CORPORATION) | Miyagawa, Yoshihiro (INPEX CORPORATION) | Watanabe, Takumi (INPEX CORPORATION)
CO2 injection is one of widely applied enhanced oil recovery (EOR) techniques, moreover, it is expected to contribute to the climate change from a viewpoint of storing CO2 in reservoir. However, CO2 is well known to accelerate precipitating asphaltenes which often deteriorate production. To understand in-situ asphaltene-depositions, unevenly distributed in composite carbonate core during a CO2 flood test under reservoir conditions, were investigated through numerical modelling study.
Tertiary mode CO2 core flood tests were performed. A core holder was vertically placed in an oven to maintain reservoir temperature and to avoid vertical segregation. A composite core consisting of four Ø1.5" × L2.75" plug cores, which had similar porosity range but slightly varied air permeabilities, was retrieved from a core holder after the flooding test. The remaining hydrocarbon was extracted by Dean-stark method, and heptane insoluble materials were extracted from each plug core via IP-143 method to observe distribution of asphaltene deposits. The variation of asphaltene mass in plug cores was investigated to explain its mechanism thermodynamically.
The core flood test was completed to achieve a certain additional oil recovery by 15 pore volume CO2 injection without any unfavorable differential pressure. The remaining asphaltene mass in each plug core revealed a trend in which more asphaltene collected from the inlet-side core. We assumed a scenario to explain the uneven asphaltene distribution by incorporating the vaporized-gas-drive and CO2 condensing mechanism. Namely, asphaltenes deposited immediately when pure CO2 contacted with oil. The contact between more pure CO2 and oil might be more frequently occurred in inlet-side core. To reproduce the scenario, a cubic-plus-association (CPA) model was generated to estimate asphaltene precipitating behavior as injected gas composition varied. In the first plug core, more pure CO2 gas was considered to contact with fresh reservoir oil compared with the downstream cores which might have less pure CO2 because of its condensation. The light-intermediate hydrocarbon gas vaporized by CO2 was also considered to emphasize the trend of more asphaltene deposits in upstream-side cores. The CPA model revealed consistent phenomenon supporting the scenario.
A numerical simulation model was designed to evaluate the technical viability of in-situ upgrading using dispersed nanocatalysts in heavy oil reservoirs. Aquathermolysis reactions are represented by a practical kinetic model based on SARA analysis, being consistent with the thermodynamic characterization. With this simplified model, the API gravity enhancement in core-flooding tests was reproduced. The mathematical formulation couples mass and energy transport equations along with a rigorous three-phase equilibrium equation of state. Also, a nanoparticle transport equation was coupled to account for reversible and irreversible non-equilibrium retention, and water-oil partitioning. PVT data were matched successfully, including API gravities and oil viscosities. Reaction rates were adjusted by means of batch-reactor information, while nanoparticle retention was validated using reported single-phase core-flooding tests. Different core-flooding experiments from the literature were reproduced to calibrate the phases transport parameters, and further up-scaled to reservoir conditions. Validation of the model with experimental data suggests that the lumping scheme based on SARA analysis and the modeling of nanoparticle transport and retention, capture the most important phenomena occurring during in-situ upgrading processes. Field-scale simulations, of a sector model from an oil reservoir in the Magdalena Medio Valley basin in Colombia, showed that the in-situ upgrading with nanoparticles can increase the recovery factor up to 5% compared with typical steam injection. However, the oil upgrading achieved in the continuous injection was lower than the one obtained in the core-flooding tests. The numerical model presented in this work, which includes a dynamic nanoparticle retention model, changes on relative permeability alteration due to nanoparticle surface deposition, and a suited kinetic-thermodynamic representation, is able to describe correctly the most relevant phenomena observed during nanocatalysts in-situ upgrading process.
A Digital Twin is a software representation of a facility which can be used to understand, predict, and optimize performance to help to achieve top performance and recover future operational losses. The Digital twin consists of three components: a process model, a set of control algorithms, and knowledge.
Usually the time for commissioning a project exceeds the initial estimations, therefore delays in project completion are quite common. This is often because ICSS testing is done on a static system which does not account for how the system will react dynamically to certain scenarios such as start-ups and shutdowns. Issues such as configuration errors, loop behaviors, start-up over-rides, dead-lock inter-trips and sequence logic are difficult to predict and are impossible to anticipate during static testing. Such delays lead to higher costs and therefore reduced revenue.
This paper aims to describe the most innovative approach to Project & Operational Certainty, which addresses these issues by using a Digital Twin for commissioning support and training. One successful use of this approach was in the Culzean project, an ultra-high-pressure high temperature (UHP/HT) gas condensate development in the UK sector of the Central North Sea. A high-fidelity process model was built and fitted to the actual plant performance based on equipment data sheets. This was connected to ICSS database and graphics, offering a realistic environment, very close to the one offshore, which had the same look and feel for the operators.
Dynamic tests conducted on the Digital Twin predicted issues on the real system, which enabled potential solutions to be tested, leading to a significant decrease in the time spent and cost during commissioning. All the operating procedures were dynamically tested, which enabled us to correct errors, saving time before First Gas. Additionally, all CRO (Control Room Operators) and field technicians were trained and made familiar with the system months in advance, aiming to avoid future unnecessary trips during First Gas.
Finally, all the control loops were fine tuned in the Digital Twin and parameters were passed to off shore, to be used as first starting point. It is expected that these parameters will be very close to fine operational points, as the model used is high fidelity model and very close to real system offshore.
This paper describes a novel chemical injection system currently under development for long-term use in subsea oil and gas fields, and discusses the process being used to vet subsystems and components, and thereby increase the overall reliability of the system. Once proven and deployed, the system is expected to be a viable alternative to delivery of production fluids via umbilicals in deep water and with long stepouts from host production facilities. For decades, deepwater engineers have discussed a future in which oil and gas production systems that are typically located on floating facilities, would be placed on the seabed. The resulting subsea factory would include pumping, fluid storage, separation, power management, connections and controls all operating in the marine environment. While these technologies have proven to be reliable in the topside environment, and some have been used for short-term intervention, to date only boosting and separation systems, subsystems and components have been qualified for long-term installation on the seafloor. This paper details how the Technology Qualification Program, defined in the second edition of API RP 17Q, has been applied to qualify the novel subsea chemical injection system. The paper describes how the performance requirements were defined, together with their reliability implications, and provides examples of qualification activities.
Data-driven methods offer significant advantages in the industry, under certain conditions, over conventional methods. But reservations still exist about their use. The paper serves to bridge the gap between unclear understanding of these methods and their successful acceptance and implementation. The workflow aims to reduce the startup time of a subsea production system (SPS). A dynamic integrated model is used to adjust the scheduled SPS startup time.
The Caribbean nation hopes the auction will lead to at least two exploration projects in a region that has become increasingly attractive thanks to new discoveries and investments made in neighboring countries. This new development is the first to recover commercial quantities of oil in the UK from reservoirs that are generally considered non-productive. The explorer has so far encountered 400 ft of reservoir pay zone in an area where it has three other producing fields. The state-run offshore company has found a gas and condensate field that holds an estimated 250 million BOE. DEA Deutsche Erdoel is buying Sierra Oil & Gas, giving the German operator stakes in six new blocks off Mexico—including the Zama discovery, where appraisal drilling is now under way.
Corrosion inhibitors are often the first line of defense against internal corrosion, and effective mitigation relies on proactive monitoring and management of these inhibitors to allow for regular feedback and dose adjustment. This paper describes a novel method of chemical dosage based on time-resolved fluorescence (TRF) that allows a simple, accurate, and efficient quantification of chemicals below parts-per-million ranges, even for double (scale/scale, scale/corrosion) quantification. A study done to find the root cause of coiled tubing string failures in Montney indicated microbial-induced corrosion, leading the CT service provider to create a biocide treatment program. Rigless coiled-tubing-unit (CTU) interventions can be effective in returning to production wells that have lost electrical-submersible-pump (ESP) efficiency because of organic, inorganic, or mixed scale deposits. Sour gas is being produced from a number of carbon-steel-completed wells in the US, Canada, France, and Saudi Arabia.
A new enabling technology known as electrically heat-traced flowline (EHTF) will be used to enable system startup and shutdown and to maintain production fluids outside of the hydrate envelope during steady-state operation. The chemical reactions creating buildups of scale that can clog a well can be replicated in a chemical lab, but researchers are finding many more variables on the surfaces of pipes that need to be considered. Comprehension of the mechanisms that influence wax deposition in oil-production systems has not yet been achieved fully. This paper investigates the influence of the Reynolds number on wax deposition. Erosion caused by fine solid particles presents one of the greatest threats to oil and gas flow assurance, consequently affecting material selection and wall-thickness design.
Asia's first rigless subsea stimulation was executed in 2018, with intervention performed upon three target wells offshore Sabah Malaysia, at a water depth of approximately 1400 m (4,593 ft). Significant changes in reservoir performance prompted an acid stimulation and scale squeeze treatment, designed to remedy fines migration and scaling issues within the well and production system. Treatment fluids were delivered subsea by an open-water hydraulic access system, using a hybrid coiled-tubing downline. Access to the subsea trees was permitted via a patented choke access technology, allowing for a flexible, opex-efficient, and low-risk intervention. The intervention system was installed upon a multi-service vessel, with the downline deployed via the vessel moonpool. A second support vessel was used as required to provide additional fluid capacity without disturbing primary intervention operations. This enhanced the flexibility of the operation, permitting changes in the treatment plan to be accommodated for without impact to critical path stimulation activities.
The full intervention was delivered as an integrated service, with all elements supplied by a single provider, via one contract. An established network of in-house equipment, expertise, test laboratories, and operational bases supported the planning and execution of the project. This was complemented by select external providers for vessels, remotely operated vehicle services, and other specialist contractors.
The challenges faced during this new market entry included completion of a comprehensive treatment fluid test program, importation and logistics of equipment from around the globe, and managing operational risks, all within a condensed timeline to satisfy a brief intervention window. By leveraging the diverse global network of the service provider, the technology and people required for the project were accessed and brought together to achieve a collaborative solution. This was enhanced by the inclusion of performance based elements within the contract. The provision of a highly efficient and flexible well access technology also supported rapid mobilization and operational risk reduction.
Post-stimulation well testing confirmed an average increase in oil productivity of 86%, with a corresponding productivity index factor (PIF) gain of 3.4. These results, combined with the efficient execution of the campaign, confirm the appropriateness of open-water hydraulic access using coiled-tubing for performing cost-effective stimulations on complex subsea wells.
Successful entry to the region was highly dependent upon the integrated nature of the service. Access to the service providers global network permitted a high degree of influence upon the ultimate performance of the stimulation. Examples include the PIF results achieved and the responsive actions taken to remedy offshore challenges such as reservoir lock-up on well #3.