Jackson, A. C. (Chevron Corporation) | Dean, R. M. (Chevron Corporation) | Lyon, J. (Chevron Corporation) | Dwarakanath, V. (Chevron Corporation) | Alexis, D. (Chevron Corporation) | Poulsen, A. (Chevron Corporation) | Espinosa, D. (Chevron Corporation)
Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results.
Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments.
The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity.
Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells.
The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.
The Vega subsea field in Norway has been producing successfully using a continuous Mono Ethylene Glycol (MEG) injection, topped up with corrosion inhibition means. A topside reclamation process allows reuse of MEG, however, limits the possibilities to produce saline water. In order to manage wells producing saline formation water and to increase ultimate recovery, a new flow assurance and integrity philosophy without continuous MEG injection is considered. This paper describes the options on hydrate as well as integrity management and the modifications both on the subsea and topside facilities required to enable an operational philosophy change. This change of the operational philosophy appears feasible, using either timely depressurization or Low Dosage Hydrate Inhibitors (LDHI) as well as a film building corrosion inhibitor in the system.
We all identify the need to integrate climate change into corporate strategy, with a profitable Carbon Capture Utilisation & Storage (CCUS) business model the elusive goal. Today, CCUS forms 10% of the R&D program of Total, a founding contributor to the OGCI Climate Investments fund. Here in the North East of Scotland, UK and Scottish Governments, along with project developer Pale Blue Dot Energy and Total are providing match funding to the European Commission’s Connecting Europe Facilities fund to progress feasibility work on the Acorn CCS project. As society continues to drive an expectation beyond hydrocarbons, what proposal might the North East of Scotland offer in response?
To meet ambitious emissions reduction targets, the UK must envisage radical changes to the energy economy. Already affecting power generation, these changes must drive further into transport and domestic/industrial energy consumption. Two technologies which may play a part in the decarbonisation of the UK energy business are CCUS and the use of Hydrogen as an energy carrier and energy store, with several studies showing that clean hydrogen is potentially the lowest cost route to meeting UK emission targets in multiple sectors. This builds on the UK’s world class gas network infrastructure, which can be repurposed to avoid becoming stranded, avoiding the enormous expense of increasing the capacity of the electricity transmission network, much of which would lie idle during the summer. The UK gas network carries approximately three times more energy than the electricity network, at one third the unit cost to consumers, and meets winter peaks that are five times greater.
Different to previous CCUS projects, and having the Oil and Gas Authority (OGA)’s first carbon dioxide appraisal and storage licence award, ACORN is an opportunity to evaluate a brownfield CCUS solution to capture, transport and store post-combustion CO2, combined with an upside through emerging pre-combustion CO2 capture technology relating to the production and sale of bulk hydrogen produced from natural gas with a zero-emission target. Located at the St Fergus Gas Terminal – an active industrial site where around 35% of all the natural gas used in the UK comes onshore. ACORN is designed as a "low-cost", "low-risk" CCUS project, to be built quickly, taking advantage of existing oil and gas infrastructure and well understood offshore storage sites. The Acorn Hydrogen project undertakes to evaluate and develop an advanced reformation process which will deliver the most energy and cost-efficient industrial hydrogen production process whilst capturing and sequestering CO2 emissions. An initial phase offers a full-chain demonstration project, an essential step toward commissioning the concept and subsequent commercialisation of large-scale CCUS and Hydrogen deployment in the UK.
SPE Offshore Europe represents an ideal opportunity to update both the region and industry on results, observations, and conclusions with respect to the evolving development architecture, selected process technologies, Government and gas transportation regulatory engagement as this, the leading Scottish CCS project continues its journey toward a final investment decision.
Tyrie, Jeb (Bridge Petroleum) | Mulcahy, Matt (Bridge Petroleum) | Leask, Robbie (Bridge Petroleum) | Wahid, Fazrie (Bridge Petroleum) | Arogundade, Olamide (Schlumberger) | Khattak, Iftikhar (Schlumberger) | Apena, Gani (Schlumberger) | Samy, Mohammed (Schlumberger) | Sagar, Rajiv (Schlumberger) | Xia, Tianxiang (TRACS International) | Nyadu, Kofi (WorleyParsons, Advision) | Maizeret, Pierre-David (Schlumberger)
This paper describes the proposed re-development of the Galapagos Field, comprising the abandoned NW Hutton field and the Darwin discovery (Block 211/27 UKCS) which forms a southerly extension. The paper covers the initial concept and analytical evaluation, the static uncertainty model build, the dynamic model history-match, the iterations between static and dynamic modelling, the development subsea and well locations, the optimisation workflow of the advanced Flow Control Valve (FCV) completions in both producers and injectors and the facilities constraints.
The redevelopment plan involved several multi-disciplinary teams. 20 years of production data from 52 wells were analysed to identify the production behaviour and confirm the significant target that provided the basis for the development concept selection. The full Brent sequence compartmentalised stochastic static model was based on reprocessed seismic plus 14 exploration and appraisal wells. Streamlines, uncertainty sensitivities and mostly good detective work honed a history match to RFT, BHP, PLT and oil and water production. P50, P90/P10 models were selected and over 100 FCVs optimised to deliver the profiles against an identified FSPO facilities’ constraints.
Over 1,000 static models were delivered consisting of sheet sands, incised valleys and channels in heterolithic facies overprinted by a depth trend with appropriate uncertainty ranges. The high well count gave a tight STOIIP probabilistic range of 790/883/937 million stb. The early RFTs illustrated extreme differential depletion between Brent zones and subzones of the Ness. To history-match these the dynamic model retained the static model definition in the Upper Ness to capture the thin but extensive shales. The early 18-month depletion and the late steady production-injection phases were simulated separately in prediction mode and matched the Production Analysis estimated ‘future’ production giving confidence to the history matched model. The initial concept development of 4 subsea-centres, to cover the large field area, with an injector in each compartment proved a robust selection. The horizontal wells increase PI where needed and mitigate internal faulting. The optimisation of the FCVs significantly increased oil production from all zones and drastically reduced water injection and production so that the identified FPSO modifications were relatively modest. The final First Stage Field Development Plan consists of 11 producers and 6 injectors across developed and undeveloped areas confirmed robust P50 reserves of 84 million boe.
Robust concept selection allowed for early identification of production units so that constraints and modifications could be accounted for within the economic model.
The Galapagos field re-development plan is an excellent example of how detailed static and fully history matched dynamic models can lay the foundations for new technology like the optimisation of the FCVs to access bypassed reserves using significantly smaller production units with reduced requirements for power, compression, gas lift, pumping pressure, injection and production. In short, they shrank the facilities.
Subsea pipeline decommissioning for either abandonment or retrieval is hazardous for both divers and the marine environment. This presentation reports on the development of a Fast Intervention Tool (FIT) for pipeline decommissioning by Webtool with input from Chevron Energy Technology Company. The FIT reduces the risks to divers and enables a quicker operation while avoiding the need for a containment dome during pipeline cutting and retrieval.
Sophisticated measures are taken to reduce the hazards to divers and the impact on the marine environment during pipeline decommissioning. Yet, traditional cutting technologies can undermine these best intentions. Diamond wire or other types of saw are time consuming and prone to jamming as the pipe moves during the cut. The containment dome used to catch contaminants that leach out during cutting and retrieval cannot "follow" the pipe as it is retrieved via a crane, therefore additional measures are needed to plug or seal to the pipe end before retrieval. The Fast Intervention Tool presented here addresses these shortcomings.
The FIT combines lifting, crimping, injection and cutting in a single deployment frame which also contains the hydraulic control system. Deployed using a barge crane, the FIT assembly is lowered over a pipeline on the seabed, with either a diver or ROV to position it. The FIT cycle time to lift, crimp, inject sealant and cut is under 1 hour (excluding vessel or set up time) after which the pipe can now be safely recovered topside without leakage. The spike injector and blades will perform a number of cycles, therefore running costs are low; the only major consumable cost is the sealant itself. Webtool has completed FIT conceptual design and in-house development and testing and is now preparing a working prototype for hyperbaric and sea trials.
Safer and more environmentally friendly method of pipeline decommissioning.
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.
Water Alternating Gas (WAG) injection is a widely practiced EOR method for many reservoirs. One drawback of WAG is the decreased injectivity when gas, often CO2, is injected into a previously water-flooded reservoir, and a further decline of injectivity is observed as water and gas injection are alternated. We present a workflow which allows the estimation of injectivity decline using pore scale displacement simulations and reservoir simulations.
In this approach, we use a multiphase Lattice Boltzmann method to directly simulate the alternating water-gas injection at pore scale resulting in a relative permeability curve for each injection phase. The simulation input accounts for injection rate, fluid properties and spatially varying wettability for each cycle during WAG. The final distribution of fluid phases in pore space of each displacement test is used as the starting point for the next displacement cycle. This enables the simulation of imbibition-drainage cycles. Any hysteresis effects present are typically captured in the resulting relative permeability curves. These are then used in a reservoir model to obtain an injectivity index for each injection phase.
We observe a strong decline of water relative permeability after the first gas injection cycle in an oil-wet rock. Detailed analysis of the fluid phases, in particular the water phase, shows that water is well connected after the initial water flood before gas injection. As gas is injected large water blobs are partially displaced and their size significantly reduced. For this wettability scenario, water and gas are competing for the large pore system. We find that capturing the hysteresis effect in a WAG requires the direct simulation of the displacement process, in particular known pore scale phenomena such as trapping and retraction.
The novelty of this approach is to directly capture the hysteresis effect of a WAG workflow in a direct simulation of displacement at pore scale. Emphasis is put on a detailed analysis of the multiphase displacement, including visualizations and an explanation for why the injectivity during WAG is reduced, namely, water and gas are competing for the same pore space. The presented workflow enables an a priori estimate for injectivity losses in a WAG EOR approach.
Induced seismicity from the injection of fluids into the earth remains a significant concern for oilfield activities such as saltwater disposal and hydraulic fracturing operations. The number of induced earthquakes occurring in the oil and gas producing regions of the Central United States and Western Canada has been declining over the past few years, highlighting the successful implementation of improved regulations and effective operational practices. However, technical engineering and geoscience challenges remain. This opening session will explore the current state of learnings and progress since the last workshop in November 2017, and highlight forward opportunities and challenges. Differences in geology, industry practices, population, politics, and other factors lead to various regulatory responses and requirements.
This paper presents an overview of the SACROC Unit’s activity focusing on different carbon dioxide (CO2) injection and water-alternating-gas (WAG) projects that have made the SACROC unit one of the most successful CO2 injection projects in the world. Several studies explored the possibility of improving both areal and vertical sweep efficiency in mature water-alternating-gas (WAG) patterns in the Magnus oil field.
The authors detail the development of a technique based on surface-to-borehole controlled-source electromagnetics (CSEM), which exploits the large contrast in resistivity between injected water and oil to derive 3D resistivity distributions, proportional to saturations, in the reservoir. In the complete paper, the authors present a novel methodology to model interwell connectivity in mature waterfloods and achieve an improved reservoir-energy distribution and sweep pattern to maximize production performance by adjusting injection and production strategy on the well-control level. This paper addresses the challenges in modeling highly unstable waterflooding, using both a conventional Darcy-type simulator and an adaptive dynamic prenetwork model, by comparing the simulated results with experimental data including saturation maps. An integrated multidisciplinary approach is required to determine an optimal design and strategy. This paper reviews the design and implementation of a full-field interwell tracer program for a giant onshore oil field in Abu Dhabi.