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Collaborating Authors
Completion Installation and Operations
Optimizing the Deepwater Completion Process: Case History of the Tamar 8 Completion Design, Execution and Initial Performance - Offshore Israel
Healy, John (Noble Energy) | Waggoner, Steven M. (Noble Energy) | Magin, Ian (Noble Energy) | Beavers, Matt (Noble Energy) | Williams, Kevin (Noble Energy) | Hebert, Russell (Noble Energy)
Abstract A case history from Offshore Israel is presented that describes the successful delivery of one (1) ultra-high rate gas well (+250 MMscf/D) completed in a significant (11.5 TCF) gas field with 7 in. production tubing and an Open Hole Gravel Pack (OHGP). The well described, Tamar 8, was completed approximately 4 years after the start of initial production from the Tamar development. Several operational innovations and process improvements were implemented that resulted in a significant reduction in rig time. A novel multi-purpose integrated tool string design enabled the sequential drilling of the pilot hole, underreaming of the reservoir section, several fluid displacements and casing cleaning in a single trip. The completions were installed with minimal operational issues (completion Non-Productive Time, NPT = 2.6%). Production commenced in April 2017. The initial completion productivity of this new well exceeded the five wells completed in 2012. Peak production rate to date is 281 MMscf/D.
- Europe (1.00)
- North America > United States > Texas (0.69)
- Asia > Middle East > Israel > Mediterranean Sea (0.29)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.94)
- Geology > Mineral (0.68)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > South East Galeota Block > Cannonball Field (0.99)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Mari-B Field > Yafo Formation (0.99)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Mari-B Field > Noa Formation (0.99)
- (5 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- (6 more...)
Abstract The oil and gas industry has operated in Denver Julesburg (DJ) basin for many decades. Currently in the basin, increasing population density and wellbore complexity have resulted in a heightened visibility of long-term well integrity. Failure can lead to future liabilities, loss of public trust, and a revoked right to operate. Operators must demonstrate commitment to well integrity to continue operating in the basin, yet many still report sustained casing pressure (SCP) on a significant portion of wells. Because SCP corresponds to the open communication of fluids to surface, it is a direct metric of well integrity failure. Regulations require operators to report and remediate instances of SCP on all wells. On average, clients experience one well with SCP for every five drilled. As a primary well barrier element, the cement sheath is vital to well integrity improvement. Enhanced placement techniques of conventional cements failed to prevent SCP, confirming that failure is derived from post-placement dynamic conditions. The solution must account for pressure and temperature stresses, preventing and mitigating mechanical failures throughout the well life cycle. A flexible and self-healing cement design provides a twofold response that is ideal for wells in areas, such as the DJ basin, with SCP risk. Mechanical properties are optimized based on the results of a mathematical stress model. Although Portland-based cement systems can be optimized to sustain higher levels of dynamic stresses, it is impossible to avoid a mechanical failure entirely. Therefore, a self-healing function is a critical secondary feature. The self-healing mechanism is designed to activate upon contact with an invading hydrocarbon and can be formulated for any type of hydrocarbon, from high gravity oil to dry gas. Flexible and self-healing cement has been successfully designed and implemented on approximately 250 wells in the DJ basin with a reduction to 2% instances of SCP. Elimination of SCP provides confidence in long-term well integrity, which is essential to continued operation in the basin.
- Well Completion > Well Integrity (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- (3 more...)
Abstract The BP project team has considered increased reserves recovery by lowering the reservoir abandonment pressure below the initial design value. Through a multi-disciplinary approach, design assumptions and equipment ratings were systematically reviewed to determine which aspects factored into the decision to change reservoir management. Collapse loading of the 10 in. production liner was identified as a key variable. The conventional design factor, a ratio of the design load to the API collapse rating, was deemed to be an insufficient way of characterizing design margin, primarily due to the perception of conservatism in the rating. While design factors are convenient for screening a casing string against an agreed-upon set of inputs and assumptions, there is little insight gained from comparing a 1.03 design factor to a 1.02 other than one value is higher than the other. The team embarked on a scope of work to characterize the probability of collapse as a function of reservoir abandonment pressure using reliability based design (RBD). Physical testing was conducted to characterize the distribution of collapse resistance and the distribution of dimensional and strength parameters which govern collapse. The quality data sets are combined using the Klever-Tamano limit state equation to indirectly derive a distribution of collapse resistance. The destructive collapse tests provide both a direct measure of the distribution of collapse and a way to calibrate the limit state equation model uncertainty. Both the direct and indirect methods are useful in determining the probability of collapse for a design load. Load uncertainty was characterized by considering variability of conditions across the wellstock, including depth, temperature and completion configuration. Casing wear was also considered in the assessment. This paper outlines the RBD methodology used to support the decision to lower reservoir abandonment pressures. Details on how to construct the statistical collapse model are provided along with a discussion on interpretation and continuous improvement activities.
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics (1.00)
- (2 more...)
Abstract A new dynamic model for casing and tubing design with friction has been developed. This paper applies the model to a field case study, an actual installation of a single trip, multizone completion in an offshore highly deviated ERD well. This is the first application of a comprehensive model with complete friction history to both installation and in-service loads. The field case demonstrates the results of a novel dynamic model for tubular stress and displacement with changing friction loads. Recorded hookload data during completion running and calibration of effective wellbore friction coefficients provided validation of the model. Accumulation of localized stresses at critical well locations is considered. The sensitivity of worst case downhole forces to the order of operational life cycle loads including stimulation, production and gas-lift was assessed. Stresses and displacements associated with each step of the setting process for multiple isolation packers were simulated. Theory and detailed description of the dynamic model are presented in an associated paper. A dynamic model of tubing forces is necessary to predict local pipe velocity which in turn determines the magnitude and direction of the local friction vectors. Distribution and orientation of wellbore friction contact is determined by the pipe running events but then is subject to change as cement and packers are set and as downhole operating conditions change. Order of life cycle conditions such as stimulation followed by production versus production followed by workover has significant impact on the magnitude of forces at worst-case locations. The investigation included the change in tubing wellbore frictional contact when completion brine is displaced with dry injection gas in conversion to gas-lift. The model demonstrated the significance of a different order of linked operations and showed that the standard available analysis tools may overlook or fail to identify worst case loads. Potential for acute load localization due to successive stimulation and production events was quantified. Impact of migration of friction loads during cyclical load events was also evaluated. The predicted initial axial load profiles were verified with recorded hook loads and corroborated with standard torque and drag model results. Comparisons are made against a previously published analytical technique. For the first time, a dynamic friction model enables seamless integration of running loads into a fully sequential analysis of subsequent well life cycle loads for landed strings. Current industry models tend to separate installation loads from the in-service life envelope. Ability to predict the changing friction orientation on installed tubulars is significant. Modelling life cycle loads in true sequence provides more accurate results for tubular design and enables a true analysis on the real-world order of well events.
Abstract This paper describes how a multidiscipline project team incorporated artificial islands with wellhead towers (WHTs) to develop an optimized drilling scenario reaching several hundred proposed drilling targets. As part of an economic optimization plan for a field in shallow waters, a project was undertaken to explore a means of taking advantage of artificial islands to reduce field development time, costs, and potential risks. The team collaborated with multiple stakeholders to identify the fundamental objectives of the field development project. Advanced planning and visualization software made it possible to analyze various combinations of wellhead towers and artificial islands and their surface locations, with each combination representing a different drilling scenario. Each scenario was then evaluated based on four criteria: technical feasibility of well construction, total development cost, total time for development, and degree of potential risk. This paper focuses on the methodology applied for this project, and results discussed are limited to two randomly selected scenarios and do not reflect the complete results of the numerous scenarios evaluated in this study, nor do they reflect any decisions made as a result of this study. The results of the analysis demonstrated that the level of feasibility and potential risk varied greatly depending on the scenario chosen, which led to a potential project cost difference of more than several hundred million USD. Collaborative planning among all stakeholders allowed the analysis of the various development scenarios to be completed on time and on budget with fundamental objectives met.
Abstract Compaction-induced casing damage, particularly adjacent to reservoir boundaries, has been observed in many fields. As part of mitigation planning for potential casing collapse due to reservoir compaction, expensive numerical models are often employed to quantitatively assess casing strain under simulated reservoir conditions. In order to simplify casing deformation analysis and reduce analysis time, the current study was initiated to quantify the effects of depletion magnitude, rock compressibility, borehole orientation, casing diameter-to-thickness ratio (D/t ratio) and grade on compaction-induced casing deformation using finite element modelling (FEM). The model results allowed an empirical equation to be derived to predict casing strain that is sufficiently accurate for engineering applications. The objective of the study was achieved by building a series of 3D FEM models to systematically simulate the deformation of casings cemented perfectly within a horizontal reservoir that underwent up to 8.3% compaction due to depletion. To capture the pattern of casing strain variation adjacent to the reservoir boundaries, the simulations were run over a range of borehole deviations (0°, 22.5°, 50°,67.5° and 90°). For each borehole deviation, casing D/t ratios of 8.14, 19.17 and 32.67 and grades of 40 ksi, 90 ksi and 135 ksi were defined to evaluate their impact on casing strain variations. The FEM models show that casing deformation adjacent to reservoir boundaries is accommodated by radial expansion and axial shortening in vertical wellbores, while the deformation is characterized by bending in deviated wellbores. The maximum strain adjacent to reservoir boundaries varies systematically, but nonlinearly with each variable evaluated. The maximum strain increases with reservoir compaction strain, i.e. increases with rock compressibility and depletion, but decreases with increasing hole deviation. Both casing D/t ratio and grade affect casing strain, but their effects are secondary. In general, the maximum strain is greater for casings with smaller D/t ratios and higher grades at any given borehole deviation and compaction strain. The variation of the maximum casing strain with compaction strain can be described by a power law. Both its constant and exponent are functions of borehole deviation, casing D/t ratio and grade. Because of the complexity of borehole-reservoir geometry and casing plastic behavior, there is no analytical solution available to estimate compaction-induced casing strain adjacent to reservoir boundaries. Numerical models may be used to predict the casing strain, but the numerical analysis is time consuming and requires specialist knowledge. The equation proposed from this study is sufficiently accurate compared to numerical models in terms of casing strain prediction, but provides a much simpler and quicker analysis. In addition, the study provides insight on the variation of casing strain with the major controlling factors, leading to a more complete understanding of compaction-induced casing deformation.
- North America > United States > Texas (0.68)
- North America > United States > California > Kern County (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- North America > United States > California > San Joaquin Basin > San Joaquin Valley > South Belridge Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > San Joaquin Valley > South Belridge Field > Diatomite Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- (6 more...)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- (4 more...)
Abstract Optimized well clean-up planning and procedures are crucial for the effective development of offshore subsea wells and their subsequent production stage to host facilities. The objective of the well cleanup is aimed at ensuring a successful removal of the completion fluids and drill-in fluid out of the wellbore to restore connectivity with the reservoir, maximize well productivity while minimizing tensile sand failure, and properly conditioning the sand face completion (in a standalone screen scenario). To achieve this goal, the well clean-up time, bean-up procedure, rate and fluid volumes to be produced should be appropriately estimated to properly size the surface testing equipment required for the operation. Due to the highly dynamic and transient nature of the cleanup process, the use of a dynamic simulator was required to effectively capture the physics of the concurrent flow of the various phases present in the system. An extensive modelling and simulation of the unload process has been performed through the use of a dynamic multiphase simulator to assess the transient displacement of the various wellbore fluids according to several unload strategies. Potential clean-up times and volumes were assessed using flowrate ramp-up schedules designed for different completion fluid distributions in the wellbore. The constrained flowrate cases were considered to represent the constraint on the rig (restricted because of surface handling capacity issues). The well clean-up procedure was developed to minimize clean-up time, avoid formation damage, and minimize volume of formation liquids on flow back during the rig well tests. During the execution, the movement of fluids along the wellbore, surface production rates, the drawdowns and duration of clean-up to predefined targets were monitored and recorded. The acquired field data from the clean-up operation was compared against simulation prediction and validated the reliability of the predictive model. This study proves the transient multiphase simulation to be effective in capturing the physics of the multiphase flow process involved in the clean-up operation. It also demonstrates that, when appropriately done, it could be an effective tool for the planning and strategy selection for the well cleanup operation.
- North America > United States (1.00)
- Europe > Norway > North Sea > Northern North Sea (0.41)
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.86)
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > Kitan Field (0.99)
- Oceania > Australia > Timor Sea > Bonaparte Basin > Kitan Field (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > Åsgard Field > Åre Formation (0.99)
- (60 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Sand Control > Screen selection (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- (7 more...)
Abstract In horizontal and extended reach wells where long completions are run into highly deviated or lateral zones, large compression loads arise due to running friction. These loads remain locked in the string when the packer or cement sets. Dissipation of friction during life service due to string vibrations and movements redistributes these friction loads between the wellhead and packer or top of cement. A numerical approach is presented to calculate the redistributed friction load so that an accurate initial tubing load is implemented in the tubular stress analysis. The proposed methodology offers an opportunity for design optimization via accurate prediction of tubing loads when the locked-in friction loads may be a determining factor in the balance between marginal tension limits near surface and marginal compression loads downhole. The numerical approach is a simple 1D finite element model in which incremental frictional loads are decomposed and redistributed based on relative stiffness of the string uphole and downhole of each local node. Essentially each portion of the string is represented as a series spring. The methodology requires input of the estimated friction load for each incremental element during running from a standard torque-drag analysis. The results are particularly relevant for ERD, multistage completion and shale-type multizonal lateral wells, where overestimation of in-service compression above the packer or cement may pose considerable design challenges for tubular components including connections. The common assumption to ignore friction in tubing analysis is non-conservative in that it may underestimate friction loads, especially downhole at the packer. However, applying the full slackoff load downhole is also unrealistic and overestimates compression above the packer leading to costly component selection. Results from the numerical model wherein post-dissipation friction loads are redistributed show that only a part of the friction induced compression migrates to the packer. Some of the redistributed friction load results in additional tension at the wellhead. The type of trajectory, kick off depth and deviation angle are important factors for the load redistribution. The methodology presented in this work provides an approach to calculate the proportion of friction load transferred to the surface compared to the packer or cement top. The redistributed result which divides the running friction load between hanger tension and downhole compression is not always intuitive. This approach is critical for correct modelling of the initial conditions in the tubing stress analysis with significant impact on tubular cost efficiency and fit-for-purpose design and well integrity.
- Geology > Geological Subdiscipline > Geomechanics (0.51)
- Geology > Rock Type > Sedimentary Rock (0.35)
- Well Drilling > Drillstring Design > Torque and drag analysis (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Installation and Operations (1.00)
Design and Performance of Annular Pressure Build-Up APB Mitigation Techniques
Sathuvalli, U. B. (Blade Energy Partners) | Pilko, R. M. (Blade Energy Partners) | Gonzalez, R. A. (Blade Energy Partners) | Pai, R. M. (Blade Energy Partners) | Sachdeva, P.. (Blade Energy Partners) | Suryanarayana, P. V. (Blade Energy Partners)
Abstract Subsea wells use Annular Pressure Build-up (APB) mitigation devices to ensure well integrity. Type I mitigation techniques control APB by reducing radial heat loss from the production tubing to the wellbore. Type II techniques work by controlling the stiffness (psi/°F) of an annulus by modifying its contents and boundaries. Though the physics of APB mitigation is well understood, the reliability of a mitigation strategy or its interaction with other parts of the wellbore is not always quantifiable. This is partly due to lack of a unified approach to analyze mitigation strategies, and partly due to lack of downhole data after well completion. Simply stated, the engineer is hard pressed to find computational-predictive methods to assess alternative scenarios and strategies within the framework of the design basis during the life of the well. In this light, our paper presents a quantitative approach to design the currently used APB mitigation strategies, i.e., rupture disks, syntactic foams, nitrified spacers, and Vacuum Insulated Tubing (VIT). In each case, the design is linked to the notion of “allowable APB” in an annulus, which in turn, is tied to the design of the casing strings, and thus to wellbore integrity. Based on an extensive survey of published literature and patents, we also review APB mitigation techniques that have been used less frequently or awaiting proof of concept/field trial.
- Europe (0.94)
- Asia > Middle East (0.93)
- North America > United States > Texas > Dallas County (0.28)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.99)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Mad Dog Well (0.99)
- (19 more...)
Abstract Reducing deepwater development costs involves thinking about alternatives to the most conventional techniques and increasing synergies among disciplines. For deepwater well conductors, replacing the conventional jetting installation method by subsea driving constitutes, in some applications, one such cost-effective alternative. On the Moho Nord Tension Leg Platform (TLP) development in Congo, all 27 conductors were installed in only a few days with an installation barge and using subsea hydraulic hammers, an operation that would have taken a few weeks and would have cost significantly more if jetting had taken place from a deepwater rig. This paper presents, from the perspective of an operator's drilling entity, some of the experience gained from this project. First, the reasons and development concept specificities which led to preferring this installation method are introduced. Then, the main engineering steps are addressed in some detail, from the geotechnical studies and the driving predictions to the fatigue engineering of both the conductor pipe and the conductor housing, and then recommendations relative to their specifications are made. The challenges regarding the engineering and procurement planning are highlighted and briefly discussed. The selected driving methodology, from the handling of the conductors to their driving to final penetration, is also addressed. Finally, the operations are debriefed in a post-job review. Whereas conductor or pile driving has been used extensively in other applications and/or industries (shallow water drilling, offshore construction, etc.), its use in deepwater drilling operations with subsea hydraulic hammers and wellhead systems is recent and the published knowledge is therefore scarce. This paper adds to the body of knowledge by providing offshore development project managers and engineers with first-hand information about this alternative to jetting conductors, its potential benefits, and key engineering and operational challenges to be considered to make it a success.
- Africa > Republic of the Congo (1.00)
- North America > United States > Texas (0.28)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- (5 more...)