It has been demonstrated in both laboratory measurements and field applications that tertiary polymer flooding can enhance oil recovery from heterogeneous reservoirs, primarily through macroscopic sweep (conformance). This study quantifies the effect of layering on tertiary polymer flooding as a function of layer-permeability contrast, the timing of polymer flooding, the oil/water-viscosity ratio, and the oil/polymer-viscosity ratio. This is achieved by analyzing the results from fine-grid numerical simulations of waterflooding and tertiary polymer flooding in simple layered models.
We find that there is a permeability contrast between the layers of the reservoir at which maximum incremental oil recovery is obtained, and this permeability contrast depends on the oil/water-viscosity ratio, polymer/water-viscosity ratio, and onset time for the polymer flood. Building on an earlier formulation that describes whether a displacement is understable or overstable, we present a linear correlation to estimate this permeability contrast. The accuracy of the newly proposed formulation is demonstrated by reproducing and predicting the permeability contrast from existing flow simulations and further flow simulations that have not been used to formulate the correlation.
This correlation will enable reservoir engineers to estimate the combination of permeability contrast, water/oil-viscosity ratio, and polymer/water-viscosity ratio that will give the maximum incremental oil recovery from tertiary polymer flooding in layered reservoirs regardless of the timing of the start of polymer flooding. This could be a useful screening tool to use before starting a full-scale simulation study of polymer flooding in each 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.
Zhang, Nan (Statoil) | Schmidt, Darren (Statoil) | Choi, Wanjoo (Statoil) | Sundararajan, Desikan (Statoil) | Reisenauer, Zach (Statoil) | Freeman, Jack (Statoil) | Kristensen, Eivind Lie (Statoil) | Dai, Zhaoyi (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Produced water from the Bakken and Three Forks formations in the Williston Basin is notably high in total dissolved solids, which leads to many well maintenance issues related to halite scaling (salt precipitation). Fresh water is widely used to prevent halite scaling; however, initial treatment programs tend to "overtreat" the problem and leads to high operation and maintenance costs. An effort to improve halite scale management has been explored, which includes identification of wells that need fresh water injection; optimization of the fresh water volumes; minimizing deferred oil production; and preventing other scales associated with the presence of fresh water in the wellbore. Several methodologies have been applied to characterize halite scaling and achieve optimization of fresh water treatments. A scaling prediction model was developed and validated with literature data and field data. The model calculates saturation ratios and optimal fresh water volume, which provides critical inputs for treatment recommendations. Field tests have been conducted to dynamically characterize produced fluids. Results have influenced new methods for treatment and fresh water injection techniques. Halite scale inhibitors have also been examined in laboratory and field tests. This work resulted in optimizing both fresh water and chemical treatment programs to minimize halite scaling. Significant cost savings have been achieved from reduced fresh water usage, thereby lowered produced water disposal.
Yin, Decao (Sintef Ocean) | Passano, Elizabeth (SINTEF Ocean) | Lie, Halvor (SINTEF Ocean) | Gryt∅yr, Guttorm (Statoil) | Aronsen, Kristoffer (Statoil) | Tognarelli, Michael (BP) | Kebadze, Elizbar Buba (BP Exploration Operating Company Ltd)
Model tests of a top-tensioned riser model were carried out as a part of a joint industry project, with the purpose of verifying the calculations of the riser analysis program RIFLEX. Sinusoidal motion in one direction was imposed at the top end of the riser model to simulate vessel motion. The tests were carried out in still water. Bending strain and acceleration were measured in both in-line (IL) and cross-flow (CF) directions along the riser model, so that the global response could be obtained through post-processing of the measured signals. Numerical simulations were performed and the results were compared with results from the model tests. This paper discusses interesting aspects of this comparison as well as the general dynamic behaviour of the top tensioned riser.
It was found that the dynamic responses of a top tensioned riser with vessel motion can consist of not only the in-line responses due to vessel motion at the riser top end, but also cross-flow vortex-induced vibrations (VIV) under conditions when Keulegan—Carpenter number is relatively small. Cross-flow VIV response is estimated using the VIVANA software and compared to the measured response. The main conclusion is however that the riser analysis program RIFLEX can predict the global dynamic responses sufficiently well.
A top-tensioned marine riser connects the offshore wellhead (WH) on the seabed and the mobile offshore drilling unit (MODU) on the free surface, conveying oil and mud. The marine riser is subject to waves, currents and motions of MODU induced by environmental loads (Yin et al., 2018).
VIV of a free-hanging riser due to vessel motion have been investigated by both experimentally and numerically (Jung et al., 2012; Kwon et al., 2015; Wang et al., 2016; Wang et al., 2017.)
Statoil and BP carried out a comprehensive model test program on drilling riser in MARINTEK's Towing Tank in February 2015. The objective was to validate and verify software predictions of drilling riser behaviour under various environmental conditions by the use of model test data. Six drilling riser configurations were tested. In the present study we only consider the simplest configuration, a top-tensioned bare riser with pinned boundary condition (Yin et al., 2018).
Kim, H. (Norwegian University of Science and Technology) | Lundteigen, M. A. (Norwegian University of Science and Technology) | Hafver, A. (DNV-GL, Oslo) | Pedersen, F. B. (DNV-GL, Oslo) | Skofteland, G. (Statoil)
Systems-Theoretic Process Analysis (STPA) is a recently developed hazard identification technique that is based on control and systems theory. Previous studies on STPA emphasize two major strengths of the method: (1) STPA provides a systematic top-down approach that enables early identification of system flaws, and (2) STPA covers a wider scope of hazards compared to traditional methods. Despite these advantages, there are only a limited number of studies that have applied the method to subsea systems. It is therefore of interest to investigate how STPA can be used to formulate new or verify existing requirements to safety-critical systems for subsea facilities. One example is the isolation of subsea wells initiated by the platform emergency shutdown (ESD) system. The purpose of this paper is to apply STPA to this function, and to discuss opportunities, challenges and possible implications of the results obtained from the analysis.
The paper starts with a thorough literature study and includes an analysis of the insights and recommendations made from other industry sectors and application areas. This review is followed by the STPA analysis of the proposed system, with focus on the identification of the unsafe control actions and safety constraints for subsea well isolation. It is investigated how STPA is able to address specific design philosophies and subsea operating conditions, like fail-safe function of subsea ESD valves, long distance between top-side control system and subsea valves, and dynamic behavior of the control structure. The paper concludes with discussions and suggestions on how the STPA procedure may be improved for application to subsea systems.
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.