Recently, there has been a drive towards a risk-based approach to plug & abandonment (P&A) design. To apply a risk-based approach for decision-making, i.e. to decide if a P&A design is acceptable or not, risk acceptance criteria have to be established and be approved by authorities. This paper presents the core of a risk-based approach, and then present three alternative risk acceptance criteria based on leakage risk of permanently plugged and abandoned wells.
The core elements of the risk-based approach for evaluation of the containment performance in permanently plugged and abandoned wells consist of estimating probability of leakage and associated leakage rates for any proposed P&A design. These will then have to be used to evaluate the acceptability of the design, by comparing them to some defined acceptance criteria. Different principles can be followed to define such criteria, such as being consistent by accepting risk levels which have been considered acceptable in other situations, environmental survivability or considering the cost-benefit to optimize the allocation of funds.
The approach and principles used are described and applied in the context of P&A design. Based on the specification of an actual gas producing well that was permanently plugged and abandoned on the Norwegian Continental Shelf (NCS), a synthetic case study is established. Simulations are carried out to provide estimations of the core elements of the risk-based approach, i.e. leakage rate and probability of the leakage, for the synthetic case. Three examples of risk acceptance criteria are then presented and discussed. The estimations derived from simulations for the synthetic case study are used to exemplify the strengths and weaknesses of the three acceptance criteria.
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
Halvorsen, A. M. K. (Statoil) | Reiersølmoen, K. (Statoil) | Andersen, K. S. (Statoil) | Brurås, A. M. (Statoil) | Sylte, A. (Statoil) | Birketveit, Ø (Schlumberger) | Evjenth, R. (Schlumberger) | Du Plessis, M. H. (Schlumberger)
A new laboratory test method for qualification of scale inhibitors for carbonate, sulphate and sulphide scale has been demonstrated. The new method reflected conditions at the first stage separator at Gullfaks A in a more realistic way than by use of the more common dynamic tube blocking test. Results of this method have been compared with dynamic tube blocking and static scale inhibition tests and a full-scale field test.
The method developed includes iron particles, realistic H2S and CO2 pressures under anaerobic conditions allowing water chemistry similar to field conditions. The method can be utilised for water with carbonate or sulphate scale potential or a mix. A pH closer to system conditions and scaling on surfaces can be achieved without adjustment of the water composition. The residence time can be up to 5 minutes, which typically represent the residence time in for example separators. The results are interpreted through visual observations through glass coils and Scanning Electron Microscopy with Energy Dispersive Spectroscopy (SEM/EDS) analyses of steel coils.
Using the new method, significant scale was formed when the incumbent scale inhibitor was tested which was also observed in the field. Several alternative scale inhibitor chemistries were recommended for evaluation based on environmental properties, field experience and cost efficiency. When testing the chemistries with the new method only one inhibitor gave acceptable results (no scaling nor co-precipitation of scale and scale inhibitor). This inhibitor was recommended for further testing in a two-week field test. The field test included quantification of suspended solids and a filter rig test. The results from the field test confirmed the laboratory results showing that the selected inhibitor was more efficient than the incumbent.
ABSTRACT: The ability of shale formations to deform and seal the annulus around the casing has been documented in publications and industry presentations. Moreover, development of such natural seals (barriers) in the annulus has been utilized in Permanent plug and abandonment (PP&A) operations as an alternative to conventional PP&A methods and materials. It has been reported that this in fact facilitated the PP&A operations and resulted in considerable cost savings. The objective of this paper is to present the work done to assess the potential of the Gearle formation in the Griffin fields in the southern Carnarvon Basin in Western Australia with respect to its ability to provide a barrier during the PP&A operations. For this purpose, we identify first and second order factors controlling the creep deformation of shales/mudstones. In turn, we compared the material and mechanical properties of Gearle formation with the formations forming seal at NCS and also with other measurements completed on other shales globally. In addition, we have utilized simple numerical creep models to assess the creep potential of Gearle formation to form a barrier around the casing. Later during PP&A operations, we acquired IBC-CBL-VDL logs in the wells and observed evidence of bonding. We, finally, present the cement log bond interpretations in the intervals we observed casing-formation bonding.
Permanent plug and abandonment (PP&A), as common industry practice, is performed by setting a number of cement plugs inside the casing strings. In certain cases, annular seal, traditionally provided by annular cement, may not fulfil the abandonment requirements and rather costly remedial cementing, milling or cut and pull of casing has to be performed in order to complete the PP&A of a well. However, certain rock types, i.e., shale and salt, have the potential to satisfy the requirements for PP&A and can therefore be used as well barrier elements as long as they can be proven to have the required strength and seal around the casing over a sufficient interval. In particular, the ability of shale to deform and seal the annulus around casing to form a barrier has been documented with the experience of operators in the Norwegian Continental Shelf (NCS) in the North Sea -providing ease of operations and cost savings (Carlsen, 2012, Williams et. al, 2009).
Installation of large subsea processing systems requires expensive specialist offshore construction and heavy-lift vessels. An alternative to larger lifted structures is towed structures. A cost-effective, versatile and open technology platform alternative has been developed, starting from the experience based on the design and installation of towed pipeline bundles for more than 35-years /1, 2/. Together with experiences from design, installation and operation of subsea plants and with the application of new materials, this has led to the new Submerged Production Unit (SPU) concept. This paper describes how the SPU, in combination with a modularised integration principle for payloads, can be applied for extensive industry collaboration on integration of existing and new subsea technologies to form large subsea production solutions replacing surface based production solutions.
Subsea processing is rapidly evolving; new technologies are routinely proposed for field application. Introduction of these new technologies, with limited or no previous operating history in the proposed environment, necessitates systematic design verification and validation. Generally, these technologies are not covered by existing rules, regulations, codes or procedures. Therefore, a different approach is required to help qualify their intended function. This paper describes a new qualification process ABS recently published. It also illustrates using the new technology qualification (NTQ) process for subsea compressors, as an example. The NTQ process can be used for qualifying other industry applications, from data analytics engines to new inspection technologies.
The NTQ process is divided into five stages: Feasibility Stage, Concept Verification Stage, Prototype Validation Stage, System Integration Stage and Operational Stage. These stages are aligned with the typical engineering product development phases of to-be-qualified equipment; and are compatible with industry Technology Readiness Levels Approaches (e.g., API RP 17N, ISO 16290). The main activities in each stage include risk assessments and engineering evaluations. These activities build, each upon the next, to determine qualification criteria and means to determine compliance with them. Results of risk assessments and engineering evaluations may lead to design improvements, or modifications to system requirements.
The proposed methodology affords industry a systems engineering-based approach for new technology qualification. The methodology is derived from many years of experience in design verification and validation of new/novel concepts for the offshore industry. The NTQ process has been successfully implemented for Independent Third-Party Review of High Pressure High Temperature designs. Lessons learned from these projects have been incorporated into the ABS Guidance Notes on Qualifying New Technologies. Upon completing the necessary requirements for each NTQ stage, a Statement of Maturity letter is awarded to the technology owner for demonstrating technology readiness for that stage. The Statement of Maturity can assist vendors in demonstrating feasibility and level of maturity for funding – as well as providing confidence to project partners, potential clients and regulatory bodies.
A differentiating feature of the new methodology is the iterative process within each qualification stage to assess the ability of the new technology to perform intended functions in accordance with defined performance requirements. Using systems engineering principles that are easily incorporated into the existing engineering process – and recognizing technology maturity at various development phases – is unique and valuable. Another key benefit of the method is the seamless transition from technology qualification, for equipment manufacturers, to class approval of an asset for owners/operators incorporating the new technology.
Subsea boosting has today achieved a significant track record and it has been recognized by major oil companies as an important part of enhanced drainage strategies. For gas fields compression is the only viable means of artificial lift and subsea compressions offers many advantages over conventional topside compression such as increased ultimate recovery. The advantages of subsea compression increase with increasing tie-back distance.
Particular features and benefits of subsea multiphase or wet gas compression are discussed in general and the particular experience with a subsea wet gas compression system now in operation at the Gullfaks field on the Norwegian continental shelf is presented.
Commissioning of the Gullfaks Subsea Wet Gas Compression System started in 2015. The system ran for one month but had to be taken out of operation for almost two years due to umbilical leakage. The system was restarted in 2017 and has been running successfully ever since, boosting wet gas and increasing the production from several wells. The system flexibility is exploited in a more extended way then ever expected during the project phase, and allows the operator to take advantage of many opportunities including increased oil recovery, and kicking off dead wells and enabling stable well back-pressure. The fundamental benefits of subsea compression are now demonstrated.
Due to the laws of physics and multiphase flow, subsea tie back systems are generally limited to approximately 110km as a single pipeline or 150km as dual pipelines after which the production plateaus are shortened and increasing amounts of reserves remain in the ground. This paper presents an overview of an innovative new technology which demonstrates that gas tiebacks can be achieved without the need of compression. The premise of the technology is to achieve pseudo-dry gas conditions through intermittent inline separation with segregated transport of the associated liquid phase. Achieving near dry gas conditions in the main production conduit removes hydraulic constraints on line size and turndown, leading to improved recovery for long distance tieback opportunities. The paper demonstrates this innovative technology and its value proposition by means of a'benchmarked' study of a 200km long gas tieback in 1,800m (5,900ft) of water. The Computational Fluid Dynamics (CFD) work has demonstrated high separation efficiencies at significant superficial gas velocities, while the required hardware fits within the installation envelope of an'Inline' pipeline tee. This has been coupled to the flow assurance work showing improvements in recoverable reserves, while leading to capital expenditure reductions of upwards of 50% due to the removal of offshore structures.
A pressure transient model to detect fault reactivation is presented in this paper. The central assumption of the fluid flow model is that fault permeability gets suddenly altered upon fault slip. The fault is modeled as a linear interface segmenting an infinite, homogeneous and isotropic reservoir into two semi-infinite regions. A constant-rate well induces pressure changes in the reservoir by either fluid withdrawal or injection that lead to fault reactivation. The mathematical model is solved via integral transforms and the analytical solution is examined at the well with the purpose to find the characteristic bottomhole pressure and pressure derivative response to a fault slip event. Typical diagnostic plots and type curves used in well testing analysis are presented. A reservoir characterization approach summarizes the application of the model presented in this paper.
The Gullfaks Shetland Group and Lista Formation (Sh/L) are fractured chalk reservoirs located above the main Gullfaks reservoirs. Fractured carbonate reservoirs are heterogeneous, due to deposition, diagenesis and fracturing, so they are challenging to characterize and model. Shetland/Lista is considered to be a type II reservoir, according to the Nelson classification (
Production by depletion started late 2012. Historical out of zone injection that occured some time between 1994 and 2010 from the Gullfaks main reservoirs increased the reservoir pressure in Sh/L. Production from Sh/L therefore initially improved the drillability to the underlying Gullfaks main reservoirs. However, presently further reduction of the pressure is not advisable to preserve the drillability. Most of the Shetland producers are consequently shut-in. Water injection to maintain the pressure is therefore considered to be a promising new drainage strategy.
In addition to pressure support, fractured, water-wet reservoirs can benefit from water injection through increased oil recovery by spontaneous imbibition. Oil can be mobilized by spontaneous water imbibition from fracture to matrix.
Special core analysis experiments indicated water-wet conditions and potential for oil recovery by spontaneous imbibition in the Shetland reservoir. Complementary field tests were conducted to confirm this:
A single well injection and following production test (push-and-pull) with tracers, confirmed high potential for spontaneous imbibition. A multi-well pilot also showed clear indications of imbibition taking place between injector and producers, when analysing production and tracer data.
A single well injection and following production test (push-and-pull) with tracers, confirmed high potential for spontaneous imbibition.
A multi-well pilot also showed clear indications of imbibition taking place between injector and producers, when analysing production and tracer data.
The objective of the work described in this paper is to confirm feasibility of a new drainage strategy, and confirm that pressure support by water injection will be beneficial for the oil recovery in the Shetland/Lista reservoirs through imbibition.