Wichtmann, Torsten (Karlsruhe Institute of Technology) | Triantafyllidis, Theodoros (Karlsruhe Institute of Technology) | Chrisopoulos, Stylianos (Karlsruhe Institute of Technology) | Zachert, Hauke (Arcadis Deutschland GmbH)
The paper presents three engineer-oriented models based on the high-cycle accumulation (HCA) model of Niemunis et al. (2005), dedicated to the prediction of long-term deformations of offshore wind power plant (OWPP) foundations caused by wind and wave action. A sublayering model for shallow foundations under vertical cyclic loading and two different approaches (a sublayering model and a stiffness-degradation model) for monopile foundations subjected to horizontal cyclic loading are presented. The results of these models are compared to the solution from 2-D or 3-D finite element simulations with the original HCA model. Furthermore, the prediction is confronted with the prognosis of other engineer-oriented models proposed for OWPP foundations in the literature. Finally, a simplified procedure for the determination of the HCA material constants is briefly explained.
The cyclic loading of offshore wind power plant (OWPP) foundations due to wind and wave action leads to permanent deformations. They may endanger serviceability since the OWPP generators tolerate only a small tilting (0.5.–1.) of the tower. Therefore, an accurate prediction of these long-term deformations is indispensable. The high-cycle accumulation (HCA) model proposed by Niemunis et al. (2005) is a suitable tool for that purpose. It has been validated based on simulations of model tests and full-scale in situ tests (Hartwig, 2010; Zachert, 2015; Zachert et al., 2014, 2015, 2016). Up to now, the HCA model has been primarily applied in finite element (FE) simulations (e.g., Wichtmann et al., 2010b; Zachert et al., 2014, 2015, 2016). Such calculations usually demand a rather laborious 3-D model and experienced knowledge on the field of FE. To facilitate the practical application of the HCA model to OWPP foundations, several simplified engineer-oriented models for different types of foundation structures have recently been developed by the authors based on the HCA equations:
• A sublayering model for the subgrade of shallow foundations under cyclic vertical loading. For example, such loading conditions are relevant for OWPPs founded on three or four separate footings. The calculation procedure using this model is similar to that in a conventional settlement calculation for foundations subjected to static loading, but with the HCA equations predicting the additional cumulative portion of settlement.
In the past, most wells have been drilled using conventional methods, but the landscape is changing as economic pressures have forced the drilling industry to refocus. Attention is at an all-time high on technologies that deliver operational efficiency and improve safety. Operators, drilling contractors, and service companies have gone through exhaustive measures to reduce cost, refine efficiency, optimize asset performance, and maximize returns. The recently introduced Schlumberger Managed-Pressure Drilling Integrated Solution offers a significant impact in all of these areas.
Managed-pressure drilling (MPD) is an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. In conventional drilling, the system is open to the atmosphere. However, with MPD, a closed-loop circulation system is created. The closed-loop system is the key element, as it enables control of the annular pressure profile through the application of surface pressure.
MPD can dramatically improve operational efficiency through the reduction of nonproductive time associated with influxes, mud losses, and stuck-pipe events. The closed-loop system improves safety by providing an increased awareness of pressure state in the well and facilitates a much higher level of control with quicker response.
The MPD drilling technique has been around for many years on land but is relatively new to deep water, as the needed technologies have only become available in the past 5 to 7 years.
While manual chokes have been the principal form of control of MPD operations since the technique was introduced, it has been noted that the consistency and repeatability of manual methods is only as good as the choke operator’s skill and the level of experience and teamwork between the driller and the choke operator. For this reason, automated MPD was introduced, and a solution now exists that addresses the many challenges associated with MPD operations.
A Shifting Business Case
Historically, MPD components have been owned and leased through various service companies. Operators have called out multiple providers to deliver the kit and execute the service.
Deepwater MPD requires substantial planning and financial investment, which has typically recurred with each call-out. On top of that has been the need to coordinate multiple service providers to work with the drilling contractor so that the system is properly integrated.
Given these requirements, operators have tended not to use the technique unless the well or hole section they are planning cannot be drilled without it. For the most part, MPD in deep water has been a contingency solution rather than a standard practice.It is difficult to build a reasonable business case around a contingency solution or a call-out service that requires such significant investment and has multiple variables at stake. Additionally, service companies must charge a premium to ensure a sufficient return on their investment.
The overarching theme of work published during the past year relating to production and facilities is performance and productivity improvement—doing more with less at a lower cost. This applies to the character of work that was performed and the topics that were investigated. The publications clearly illustrate how the low-price environment stimulated creativity in the improvement of existing operations and technologies as well as in the development of new technologies.
Nearly one-third of the papers reviewed for this feature involved the use of digital models and simulations. Models were used to verify the study results or were improved on the basis of study results. Where adequate models were unavailable, new ones were developed (paper SPE 182450). Computational-fluid-dynamics (CFD) simulations played an important role in a number of published studies. One study (paper OTC 27762) validates simulations by actual physical testing and includes an evaluation of multiphase CFD flow-modeling techniques. Overall, this year’s publications confirm the pervasive dependence of technological advancements on the use of valid and (hopefully) reliable digital modeling.
“Big data” played a role in several investigations, with objectives that ranged from optimizing field production (paper SPE 182450) to improving maintenance and lowering the cost for it (paper OTC 27788). Big data was also incorporated into project management by forward-using available information to systematically “Eliminate Decision Bias in Facilities Planning” (paper SPE 187283).
Compressors and compression are components of facilities that often show higher capital and maintenance costs, so it is not surprising that several papers described means to reduce these costs. Three papers addressed compressor failure/reliability issues (papers SPE 183322, SPE 183528, and SPE 183253), while two papers described means to improve production economics by the purposeful application of compressor technology, including the use of a multiphase compressor to improve recoveries on a marginal wellhead platform (paper IPTC 18692).
Inflow-control devices (ICDs) were addressed by several authors, with some focusing on the application of ICDs to steam-injection wells (paper SPE 183842). Others reported on the development of new types of devices that operate on electrical resistance (paper SPE 185682) or are viscosity independent (paper SPE 183930).
Finally, the use of 3D printing for oil-field applications was described in two papers (papers OTC 27540 and OTC 27766). A review of existing and emerging nanotechnology applications in the oil patch was also provided (paper SPE 183301).
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 27762 Modeling of a Full-Scale Horizontal Liquid/Liquid Separator Under Conditions of Varying Flow Rate, Water Cut, and Viscosity With Experimental Validation by A.B. McCleney, Southwest Research Institute, et al.
SPE 183842 Developing a Robust Inflow-Control Device Suitable for High-Rate Injection by Joshua Snitkoff, Baker Hughes, a GE Company, et al.
SPE 183840 A Robust Framework for ICD Design in a Giant Field Using 4D Dynamic Modeling by O.A. Ogunsanwo, Schlumberger, et al.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184074, “Microdogleg Detection With Continuous Inclination Measurements and Advanced BHA Modeling,” by K.A. Mills, SPE, and S. Menand, SPE, DrillScan, and R. Suarez, SPE, Nabors, prepared for the 2016 SPE Eastern Regional Meeting, Canton, Ohio, USA, 13–15 September. The paper has not been peer reviewed.
Microdoglegs are a natural effect of any vertical or directional well that can explain a wide variety of downhole problems. A trajectory-prediction model able to calculate the inclination and azimuth approximately every 12 in. has been developed to estimate microdoglegs using standard surveys, bottomhole-assembly (BHA) data, and steering parameters. This new methodology combining downhole data measurements with drillstring-modeling analysis highlights the potential for drilling optimization and wellbore placement.
Standard Surveys. Surveys are generally taken at an interval of every 95 ft, the length of one stand. While the general recommendation is to decrease the survey interval when building faster than 3°/100 ft, this is often neglected because there is no advantage seen in wellbore-positioning-uncertainty models.
The well path between each survey point typically is calculated using the minimum-curvature approach, which assumes a curve of equal angle along the surface of a sphere with only one radius in a 3D plane. Looking at the well as a whole, this approach appears logical and yields reasonable-looking trajectories; however, when examining more-frequent survey data, it becomes obvious how this method can mislead users to think that the well path is much smoother than it actually is. Continuous-survey measurements have enabled the industry to take a closer look at what is happening between survey points, in highlighting microdoglegs quite often undetected by standard surveys.
Continuous Surveys. Doglegs are generally discussed on a well level. Wells are analyzed for tortuosity looking at the change in trajectory from one survey point to the next. Little thought is given to what changes happen between those points unless a dysfunction occurs. Aggressive directional work can lead to the creation of microdoglegs, or doglegs on a scale of a few feet. Quick changes in direction create microdoglegs, which can contribute overall to higher torque and drag.
In examining continuous surveys, the actions of the directional driller can be seen clearly and doglegs can be examined more closely. While continuous-survey data have become more common in the industry, not all measurement-while-drilling (MWD) tools are equipped for the measurements and, generally, data must be processed at surface on the basis of the previous survey. In the absence of continuous-survey data, BHA modeling run on a step-by-step basis can aid in wellbore placement, failure analysis, and post-well evaluation.
The results obtained from a field lateral loading test and the existing p-y curve models were compared to develop a p-y curve model applicable to the basalt at Jeju Island. The results of the comparison demonstrated underestimated values for the initial tangent modulus and the ultimate subgrade reaction from the p-y curve models presented by Carter and Kulhawy (1992) and overestimated values from the p-y curve model suggested by Yang and Liang (2006). Therefore, in this paper, the initial tangent to a p-y curve suggested by Carter (1984) was modified according to the behavior of the basalt at Jeju Island.
Recently, the exploitation of offshore wind turbines worldwide has been gradually increasing on the basis of the prospects for a new infrastructure for the energy industry that is currently unavailable for onshore wind turbines owing to issues associated with noise, the landscape, and the deficiency of necessary sites.
Thus, active research on source technologies to establish offshore wind turbine systems and optimal large complexes is currently in progress in Korea. Among the sites of large complexes for offshore wind turbine systems, offshore Jeju Island was determined to be one of the optimal places for an offshore wind turbine system due to its favorable windy conditions. Therefore, efforts to develop a marine wind power generation system and associated planning activities are concentrated there.
The representative types of pile foundations required for offshore wind turbines are the monopole, jacket, and tripod, from which an optimal type of pile foundation is determined by the consideration of various factors such as the type and characteristics of the seabed, the depth of the water, the tidal current, the waves and winds, and the economy.
The pile foundation is a substructure designed to support vertical and lateral loads for places where it is difficult to install direct foundations to support upper-structure loads due to soft ground or places with high-water levels, and it is typically designed to resist axial loads. However, offshore wind turbines are frequently subjected to large lateral loads induced by the wind load, the current load, and wave loads. Thus, pile foundations applied to offshore wind turbines should be designed to resist lateral loads as well as axial loads.
O'Reilly, Daniel I. (Chevron Australia and University of Adelaide) | Hopcroft, Brad S. (Chevron Australia) | Nelligan, Kate A. (Chevron Australia) | Ng, Guan K. (Chevron Australia) | Goff, Bree H. (Chevron Australia) | Haghighi, Manouchehr (University of Adelaide)
Barrow Island (BWI), 56 km from the coast of Western Australia (WA), is home to several mature reservoirs that have produced oil since 1965. The main reservoir is the Windalia Sandstone, and it has been waterflooded since 1967, whereas all the other reservoirs are under primary depletion. Because of the maturity of the asset, it is economically critical to continue to maximize oil-production rates from the 430 online, artificially lifted wells. It is not an easy task to rank well-stimulation opportunities and streamline their execution. To this end, the BWI Subsurface Team applied the Lean Sigma processes to identify opportunities, increase efficiency, and reduce waste relating to well stimulation and well-performance improvement.
The Lean Sigma methodology is a combination of Lean Production and Six Sigma, which are methods used to minimize waste and reduce variability, respectively. The methods are used globally in many industries, especially those involved in manufacturing. In this asset, we applied the processes specifically to well-performance improvement through stimulation and other means. The team broadly focused on categorizing opportunities in both production and injection wells and ranking them—specifically, descaling wells, matrix acidizing, sucker-rod optimization, reperforating, and proactive workovers. The process for performing each type of job was mapped, and bottlenecks in each process were isolated.
Upon entering the “control” phase, several opportunities had been identified and put in place. Substantial improvements were made to the procurement, logistics, and storage of hydrochloric acid (HCl) and associated additives, enabling quicker execution of stimulation work. A new program was also developed to stimulate wells that had recently failed and were already awaiting workover (AWO), which reduced costs. A database containing the stimulation opportunities available at each individual well assisted with this process. The project resulted in the stimulation of several wells in the asset, with sizable oil-rate increases in each.
This case study will extend the information available within the oil-industry literature regarding the application of Lean Sigma to producing assets. It will assist other operators when evaluating well-stimulation opportunities in their fields. Technical information will be shared regarding feasibility studies (laboratory-compatibility work and well-transient-testing results) for acid stimulation and steps that can be taken to streamline the execution of such work. Some insights will also be shared regarding the most-efficient manner to plan rig work regarding stimulation workovers.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27788, “Digitalization of Oil and Gas Facilities Reduces Cost and Improves Maintenance Operations,” by H. Devold, T. Graven, and S.O. Halvorsrød, ABB, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
The digitalization of oil and gas facilities is becoming a new technical arena. Effective solutions can be used to convert data into information and knowledge, which can then be used to improve maintenance operations. This paper discusses several aspects of this process, ranging from a discussion of maintenance strategies to the opportunities presented by extracting new information from big data.
Fieldbuses, device diagnostics, and advanced management-and-control systems collect large amounts of data, but acquiring and applying methods of exploiting the data have lagged. End users have expressed doubts that they are realizing value from these solutions and have wondered whether a return to simpler systems is needed. In this paper, the authors conclude that condition-based maintenance can reduce the cost of maintenance operations significantly and that further potential in predictive-maintenance regimes exists as experience with base data is gained.
Reactive, Scheduled, and Condition-Based Maintenance Strategies
A reactive, or break-and-fix, type of maintenance strategy will often present the lowest maintenance operation cost, seen in isolation. But also implied is the cost of production unavailability, the safety risk posed by very hazardous events, and the risk of high repair costs after catastrophic equipment failure.
Scheduled or periodic maintenance requires one to estimate failure modes and consequences for all equipment in the plant; then, on the basis of the equipment’s expected lifetime, one calculates inspection intervals and replacement cycles. Because this is often impractical to perform for each individual piece of equipment, equipment is divided into classes depending on type and is given maintenance that is based on that type and its criticality. This approach can have some undesirable effects, including the following:
We develop and use a new data-driven model for assisted history matching of production data from a reservoir under waterflood and apply the history-matched model to predict future reservoir performance. Although the model is developed from production data and requires no prior knowledge of rock-property fields, it incorporates far more fundamental physics than that of the popular capacitance–resistance model (CRM). The new model also represents a substantial improvement on an interwell-numerical-simulation model (INSIM) that was presented previously in a paper coauthored by the latter two authors of the current paper. The new model, which is referred to as INSIM-FT, eliminates the three deficiencies of the original data-driven INSIM. The new model uses more interwell connections than INSIM to increase the fidelity of history matching and predictions and replaces the ad hoc computation procedure for computing saturation that is used in INSIM by a theoretically sound front-tracking procedure. Because of the introduction of a front-tracking method for the calculation of saturation, the new model is referred to as INSIM-FT. We compare the performance of CRM, INSIM, and INSIM-FT in two synthetic examples. INSIM-FT is also tested in a field example.
Surfactant-based enhanced oil recovery (EOR) is a promising technique because of surfactant’s ability to mobilize previously trapped oil by significantly reducing capillary forces at the pore scale. However, the field-implementation of these techniques is challenged by the high cost of chemicals, which makes the margin of error for the deployment of such methods increasingly narrow. Some commonly recognized issues are surfactant adsorption, surfactant partitioning to the excess phases, thermal and physical degradation, and scale-representative phase behavior.
Recent contributions to the petroleum-engineering literature have used the hydrophilic/lipophilic-difference net-average-curvature (HLD-NAC) model to develop a phase-behavior equation of state (EoS) to fit experimental data and predict phase behavior away from tuned data. The model currently assumes spherical micelles and constant three-phase correlation length, which may yield errors in the bicontinuous region where micelles transition into cylindrical and planar shapes.
In this paper, we introduce a new empirical phase-behavior model that is based on chemical-potential (CP) trends and HLD that eliminates NAC so that spherical micelles and the constant three-phase correlation length are no longer assumed. The model is able to describe all two-phase regions, and is shown to represent accurately experimental data at fixed composition and changing HLD (e.g., a salinity scan) as well as variable-composition data at fixed HLD. Further, the model is extended to account for surfactant partitioning into the excess phases. The model is benchmarked against experimental data (considering both pure-alkane and crude-oil cases), showing excellent fits and predictions for a wide variety of experiments, and is compared to the recently developed HLD-NAC EoS model for reference.
A new methodology for the joint optimization of optimal economic project life (EPL) and time-varying well controls is introduced. The procedure enables the maximization of net present value (NPV) subject to satisfaction of a specified modified internal rate of return (MIRR). Knowledge of the economic project life enables the operator to plan for infill drilling or some other type of field development in the case that the lease/contract duration is longer than the optimal project life. This will enable NPV to be maximized, and the hurdle rate to be honored, over the entire duration of the lease. The optimization is formulated as a nested procedure in which economic project life is optimized in the outer loop, and the associated well settings [time-varying bottomhole pressures (BHPs) in the cases considered] are optimized in the inner loop. The inner-loop optimization is accomplished by use of an adjoint-gradient-based approach, while the outer-loop optimization entails an interpolation technique. The successful application of this framework for production optimization for 2D and 3D reservoir models under waterflood is demonstrated. The tradeoff between maximized NPV and rate of return is assessed, as is the impact of discount rate on optimal operations. In the second example, we illustrate the advantages of initiating a new project (that satisfies the hurdle rate) once the EPL is reached. Taken in total, the results in this paper demonstrate the importance of explicitly incorporating both NPV and rate of return in production-optimization formulations.