Subsea sampling interface
The subsea sampling interface (SSI) is installed in the subsea tree or manifold to capture sample fluids upstream of the SMPFM. It can be installed as a hardware structure or be included in a retrievable flow control module (FCM) – SMPFM and choke module – on the SPS. In this case, the sampling interfaces, barriers, etc., are packaged in a dedicated fluid sampling FCM with provision for interchangeability to standard production FCM. It is designed to capture a representative sample of each phase (oil, water, and gas) in a wide range of flow conditions, taking into consideration flowrates, phase distribution, and physical properties.
The SSI includes sampling lines that tap into the production flow path, and the remotely activated valves, 2 or 4 on each sampling line, depending on requirements, all of which are fail-safe in the close position. The ROV provides the connections between the SSI and the sampling skid. The SSI can be configured for vertical access sampling, as is normally required for manifolds, or for horizontal access as the preferred option for integration into an SPS tree.
Sampling operation is done in a steady condition to secure representative samples over a certain time period in the flow-loop. This ensures sample accuracy in case of unstable flow and provides the volume needed to perform laboratory analysis topside. The SSM can house 9 to 12 sample bottles, based on project specific requirements. To maximize value on the sampling operations is to incorporate the subsea fluid sampling program into the periodic subsea intervention operations to reduce the high cost of vessel entry and ROV deployments.
While there are benefits, there are still limitations to their deployment, recovery methods, payload ratings, dexterity, and available power sources. Equipment for retrieval and deployment can be mounted on the ROV, allowing for greater payload and complexity, especially in the case of the subsea sampling operations. This could restrict access due to the physical size of the combined ROV and sampling skid during operations. However, research on ROV manipulation and deployment is ongoing for subsea intervention operations. By exploring cost effective solutions, such as the virtual fluid sampling model, the subsea industry can manage the challenges faced by reservoir production uncertainty.
|Convergence tests on the simulated numerical pressure results at 5s, 10s and 20s time interval over 6,000 m (19,685 ft). (All graphs courtesy Eni)|
Integrated virtual model
The development of an integrated fluid sampling model was based on virtual compositional fluid tracking results. This captures the essential elements of the simulation model to compare both the input and output of simulated results to check and verify the performance of the SMPFM.
This development is a cost-effective subsea reservoir fluid sampling approach to reduce the frequency of operations in retrieving a subsea sample with the potential to reduce the costs of intervention and risk of exposure to the subsea environment. To achieve operational success with the integrated virtual fluid sampling model, an optimized novel sampling strategy was developed for deepwater field development.
This sampling strategy is required on each individual production well, depending on the pressure profile of the well during early-, mid-, and late-life of subsea field operations. The integration and benefits of applying this strategy add value to the virtual compositional fluid tacking model application. The virtual fluid sampling model would be a useful predictive tool for operators and regulatory authorities to manage the challenges on subsea fluid sampling operations for accurate understanding of the reservoirs and impact on production facilities.
A deepwater field off West Africa validated the results in a case study. It showed a simulated pressure profile with compositional fluid tracking, which was compared with the experimental base pressure data from a test loop facility.
The validation provides accurate PVT and compositions of reservoir fluid properties of the subsea tree. A transient multi-phase flow simulation environment was selected to develop the virtual fluid sampling model, capturing the essential building blocks of the SPS and simulations to test the model.
Pressure results of the test show that the convergence of pressure drops from 726.6psi (50 bar) down to 725 psi (49.9 bar) over 20,000 seconds. Comparing the simulated numerical results with experimental results, the pressure at 730 psi (50.3 bar) shows that at 300 m (984 ft) of pipeline length, the simulated results have a 3% drop in pressure from the experimental result. This is from the relatively low pressure due to slip mode effect, liquid hold up, slugging, or turbulence, in the multi-phase flow caused by pressure fluctuations. Also, as the pressure drops to 715 psi (49.2 bar) along the pipeline length of 2,650 m (8,694 ft), the simulated pressure was in phase with the experimental pressure. This is due to steady conditions of the multi-phase flow. So at a 50% drop of total pressure, the pressure is representative of the experimental results.
A convergence test analysis shows a pressure drop of 700 psi (48.2 bar) at the 4,700 m (15,420 ft) along the pipeline. The simulated pressure exhibited the same result with less than 2% slip mode effect of the fluid compositions on multiphase flow. This demonstrates that both results are represented with the pressure trend. Therefore, acquired results of the validation of the virtual fluid sampling model provide a predictive tool to track fluid compositions in multi-phase flow. This enables representative fluid sampling that can inform operational conditions of subsea production facilities, for proactive monitoring and cost efficient operations.
The integrated virtual fluid sampling model benefits oil and gas production. It provides the capability to improve the understanding of well stream flow and retrieve information from parts of the production system that instrumentation can not reach. It enables a proactive and cost-effective sampling operation on a subsea production facility, allowing the development of advanced operational monitoring through the life-of-field.
Thus, the capability of the integrated virtual fluid sampling model has been demonstrated to track fluid compositional changes, an innovative breakthrough, where field measurement instruments can not reach. It also provides an enhanced strategy to manage field production operations. The model presents a predictive tool to match the performance of SMPFM for accurate monitoring of the well stream fluid. Therefore, with the integrated virtual fluid sampling model, a separate check on SMPFM is achievable.
Synergy in deepwater development
The combination of operational and system strategies provides the right optimization to maximize asset value in deepwater developments. Employing the synergies of subsea fluid sampling (physical and virtual sampling), subsea processing (conditioning, separation, boosting, compression and re-injection), treatment of fluid through injection of chemicals on subsea facilities, operational control philosophy, and the planning of step outs/architectures enables a holistic development of deepwater assets.
Subsea fluid sampling adds value in field developments, which is demonstrated in a typical application to test the characteristics of different fluid components on a merging network. This is applicable for well streams commingling into a manifold, and for tracking individual components of the well to provide an accurate measurement and allocation of production revenue, as well as when to employ subsea processing during the life-of-field development.
After a subsea separation process, water can be re-injected into the reservoir with reduced energy consumption required to deliver the separated hydrocarbon fluid produced to the topside facilities. The synergy of fluid sampling and subsea processing provides an optimized approach to maximize growth in hydrocarbon volume production.
While project planning, one needs to understand when to introduce subsea processing; not all fields require major processing at the early phase of production. If an initial field study indicates that water breakthrough is not expected until after the third year of production, it may not be necessary to install water separation equipment from the start. Also, if the natural flow pressure is sufficient, then boosting equipment may not be necessary until the third year of production. Therefore, a proper field assessment study is required before making any final investment decisions about using subsea processing to maximize asset recovery.
By acquiring subsea fluid samples, accurate fluid properties are obtained, which are essential for effective reservoir evaluation and management. Retrieving accurate fluid samples are linked to the value creation and realization in employing subsea processing on field development. The synergy between the developed virtual fluid sampling model and ROV deployed fluid sampling have been identified as the optimal solution to acquire representative fluid samples, to validate and calibrate SMPFM.
Based on a paper presented at the Deep Offshore Technology International Conference & Exhibition held in Aberdeen, Scotland, October 14-16, 2014.