Last year, we reviewed some of the more-prominent examples of how the industry continues to respond to the need for safe and cost-effective production facilities in ever-more-challenging environments. We also highlighted the increasingly important role that constructive collaboration can play in facilitating the desired outcomes for all parties. This year, we illustrate how this same theme of constructive collaboration has been applied effectively at the other end of an offshore facility's life span, in the major decommissioning program for the Frigg field. Most of us are very familiar with the term offshore hookup, but soon we may become equally familiar with what offshore "hookdown" really involves. We also take a look at an approach for safely extending the useful life of aging offshore- production infrastructure, in locations where the subsea tieback of new fields warrants the associated investment.
Major performance challenges for deepwater applications from a drill bit standpoint were identified as (1) High surface torque in salt is one of the major ROP limiters. (2) Inability to control depth of cut in soft rocks including shale and salt and when drilling in interbedded formations results in torsional oscillations and stick-slip. (3) Improper combination of bit and reamer induces drillstring vibrations. This paper presents the development of new drill bit technologies combined with a new system matching analysis package to address those problems.
Salt mechanical behavior was evaluated using triaxial testing under confining pressures up to 5,000 psi. Full scale pressurized testing was then conducted to evaluate salt drilling behavior versus rock characteristics. The following specific challenges were addressed: Non-planar PDC geometries were tested in salt, among other rocks, to identify a geometry which results in maximum increase in ROP at any given torque. New insert shapes were developed and tested for more effective and accurate depth of control. A full drillstring analysis model was developed with the ability to predict downhole and surface torque and WOB as well as drillstring dynamics, torque, and drag.
Non-planar PDC geometries were tested in salt, among other rocks, to identify a geometry which results in maximum increase in ROP at any given torque.
New insert shapes were developed and tested for more effective and accurate depth of control.
A full drillstring analysis model was developed with the ability to predict downhole and surface torque and WOB as well as drillstring dynamics, torque, and drag.
The new shaped cutter full scale pressurized test resulted in an increase in ROP/torque ratio throughout the different rock and a 28% increase in salt. The cutter also increased ROP/WOB ratio by 42%. Furthermore, the new insert shapes proved to be more effective in controlling depth of cut, resulting in an extra 35% reduction in torque/WOB ratio compared to standard insert shapes.
The project is now in field evaluation and the new drill string analysis tool has been applied to several field applications including some in the Middle East, North Sea, Gulf of Mexico, and the Caribbean for different purposes. Some of those purposes include buttonhole assempbly (BHA) selection for given bit and reamer, bit selection for a given BHA design and reamer, and drilling parameter optimization for a given BHA design, bit, and reamer. New insert shapes were run in multiple applications in North America, including in North Dakota and Oklahoma, with promising results proving that although the project was focused on deepwater drilling challenges, the novel solutions are applicable to a wide range of applications.
Boushari, Mohammed (Kuwait Oil Company) | Hindi, Khaled Al (Kuwait Oil Company) | Dashti, Mohammed (Kuwait Oil Company) | Joby, Jacob (Kuwait Oil Company) | Hazarika, Manoj (Kuwait Oil Company) | Carasco, Anant (Schlumberger) | Najdi, Faisal Al (Schlumberger) | Saleh, Rashad Mohiey (Schlumberger) | Jokhi, Ayomarz (Schlumberger) | Bandi, Mani (Schlumberger) | Benny, Naveen (Schlumberger) | Shar'an, Ismail Qasem Mohammad Al (Schlumberger) | Fernandes, Daniel (Schlumberger) | Nair, Prakash (Schlumberger) | Helal, Karim (Schlumberger) | Hassan, Said (Schlumberger) | Mustafa, Mohammed Mobasher (Schlumberger) | Abdelbaset, Shady Moustafa (Schlumberger) | Dashti, Sulaiman (Schlumberger) | Kubaish, Yasser Al (Schlumberger)
Drilling a large directional hole section through the Middle East's hard carbonate formations using a polycrystalline diamond compact (PDC) bit and a rotary steerable system (RSS) bottomhole assembly (BHA) equipped with an expandable underreaming-while-drilling (UWD) tool presents a number of challenges. An operator was experiencing high-lateral vibration, stick/slip, and whirl-induced drilling dysfunctions, causing premature downhole tool fatigue failures. To reduce reaming runs and bit trips, a finite element analysis (FEA) -based dynamic simulation system was used to quantitatively analyze the complex interaction of various manufacturers’ downhole tools to optimize the BHA configuration and drilling parameters. Formation-related challenges were present in the carbonate formations, typically limestone and dolomite, known to be hard and interceded, along with the chances of well kick or complete losses, in addition to the shale formations, which are reactive as well as tectonically unstable. The shale formations tend to fall out if incorrect mud weight is applied. Also, the abrasive sandstone formations, comprised of interbedded shales, are reactive and mechanically unstable.
The goal of the drilling operation was to effectively match the PDC and reamer cutting structures to minimize vibration. A modeling tool was used to define an optimized set of operating parameters for efficiently drilling the upper limestone, multiple limestone and dolomite transitions, and the difficult lower dolomite formation. The modeling enabled the drilling team to configure a BHA, which would efficiently deliver directional requirements in the curve and tangent as well as to mitigate potential push-pull issues in the critical transition zones. The BHA, run as modeled with the optimized operating parameters, produced good quality results. The six-blade PDC- RSS combination and underreamer BHA successfully drilled and opened the 12.25-in. × 13.5-in. wellbore with minimal lateral vibration and stick/slip. The BHA drilled 2,082 ft of wellbore, including the challenging hard and interbedded formations, which consisted of 6,000 to 25,000-psi limestone and shale with moderate- to high-impact indices at a 15 to 17-ft/hr average rate of penetration (ROP) and within authority for expenditure (AFE). The BHA delivered a high-quality, in-gauge borehole and efficiently delivered all directional objectives, building hole angle from vertical to 17.8° as required. The run was the first successful directional large-hole hard-rock UWD operation with a PDC-RSS BHA in Kuwait.
The successful operation is the result of a proactive planned initiative to mitigate BHA shock loading, which included real-time monitoring using a predictive compressive-strength analysis system. The success also increased the confidence in the FEA-based modeling system's ability to accurately identify the root cause of damaging vibrations in the planning stage while underreaming the long sections of hard carbonates in the Middle East.
The horizontal wells are applied to enhance the production rate by increasing the contact area between the wellbore and reservoir, it has been also used to access the highly heterogeneous and unconventional formations. One horizontal well can produce the same amount of 5 vertical wells with a very competitive cost and operational time. Further improvement for the productivity of horizontal well can be achieved by conducting hydraulic fracture operations, especially for low permeable or unconventional formations. This paper shows a new technique to estimate the performance of hydraulically fractured horizontal wells, without a need for using downhole valves or smart completion.
In the literature, few empirical models have been proposed to evaluate the inflow performance of such wells. However, most of these models assume constant pressure drop in the horizontal section, therefore, significant errors were reported from those models. In this work, a reliable model will be presented to predict the well deliverability for hydraulically fractured horizontal well producing from heterogeneous and anisotropic formation. Different artificial intelligence (AI) methods were investigated to evaluate the well performance using a wide range of reservoir/wellbore conditions. The significant of several parameters on the well productivity were investigated including; permeability ratio (kh/kv), number of fracture stages and the length of horizontal section.
The AI model was developed and validated using more than 300 data sets. Artificial neural network (ANN) model is built to determine the production rate with an acceptable error of 8.4%. The model requires the wellbore configurations and reservoir parameters to quantify the flow rate. No numerical approaches or downhole well completions were involved in this ANN model, which reduce the running time by avoiding such complexity. Moreover, a mathematical relation was extracted from the optimized artificial neural network model. In conclusion, this work would afford an effective tool to determine the performance of complex wells, and reduce the differences between the actual production data and the outputs of commercial well performance software.
Steady increases in natural gas transportation volumes have prompted operators to reevaluate the performance of the existing gas-pipeline infrastructure. Conventional wisdom dictates that adding an additional link or a pipe leg in a gas-transportation network should enhance its ability to transport gas. Several decades ago, however, Dietrich Braess challenged this traditional understanding for traffic networks. Braess demonstrated that adding extra capacity could actually lead to reduced network efficiency, congestion, and increased travel times for all drivers in the network (the so-called "Braess paradox"). The study of such counterintuitive effects, and the quantification of their impact, becomes a significant priority when a comprehensive optimization of the transportation capacity of operating gas-network infrastructures is undertaken. Corroborating the existence of paradoxical effects in gas networks could lead to a significant shift in how network capacity enhancements are approached, challenging the conventional view that improving network performance is a matter of increasing network capacity. In this study, we examine the occurrence of Braess' Paradox in natural-gas-transportation networks, its impact, and potential consequences. We show that paradoxical effects do exist in natural-gas-transportation networks and derive conditions where it can be expected. We discuss scenarios that can mask the effect and provide analytical developments that may guide the identification of paradoxical effects in larger-scale networks.
Passive fire protection (PFP) has been used in the oil and gas industry for many years as a method to avoid/delay global collapse of offshore installations. However, location of PFP has normally been based on simplistic assumptions, standards, guidance, and methods that do not always consider the real response of the structure to fire. The resulting PFP schemes can be conservative, leading to unnecessary cost to the operator in terms of application and maintenance costs. More importantly, there is the potential for the PFP scheme to be insufficient for the actual fire hazards, which will increase the level of risk to the personnel onboard. Fire-induced progressive collapse is a function of the level of redundancy of a structure; it is for this reason that redundancy analyses have sometimes been used as a simplistic method to calculate the level of PFP required. However, this method does not take into account the size of the fire threat against which the PFP is designed and could lead to less-than-conservative results because it considers removing only one member of the structure at a time, without considering reduction in the strength of the surrounding members as they are also being heated by the fire. Performance-based fire-collapse analysis provides an understanding of the response of the individual members, as well as the entire structural system, to fire. Understanding the failure mechanisms, susceptibility to progressive collapse of the structure, and key members that must remain in place during an accident situation allows for the optimization of the PFP scheme, protecting only the required members while allowing for local failure of redundant members. The present paper provides a comparison between the different methods, and provides case studies that have resulted in optimum PFP schemes linked to design fires on the basis of acceptable risk levels. Hydrocarbon fires on offshore installations are extremely hazardous, involving large heat loads, which can have serious consequences for health, safety, and the surrounding environment. Ever since the 1988 Piper Alpha accident (Cullen 1990), the offshore industry has made increasing efforts to ensure the safety of both personnel and assets. More recently, the 2010 Deepwater Horizon (BP 2010) accident highlighted the importance of providing an adequate level of protection to offshore installations against accidental fire events. PFP has been used in the oil and gas industry for many years as a method to avoid/delay global collapse of offshore installations.
This paper analyzes the various selection methods of integrated template structures (ITSs) for use in the Arctic environment. First, an analysis of several actual projects is carried out, with the specific features of each described thoroughly. An important part of the work is devoted to the requirements of ITSs conceived in relevant NORSOK (Norsk Sokkels Konkuranseposisjon), International Organization for Standardization (ISO), and DNV (Det Norske Veritas) standards. The main elements of subsea production modules are examined in this work, along with their specific characteristics and components. Operation and installation of subsea modules in the Barents Sea are also analyzed in this paper. Four scenarios, with differing numbers of ITSs (two, three, four, and six) and differing quantities of well slots in each, are considered. For each scenario, a study of related marine operations (required for installation) is performed, and a program for installation-cost estimates is developed, resulting in the determination of an optimal design for the ITSs. Various parameters affecting the cost of subsea infrastructure are analyzed and studied from different perspectives (e.g., geometrical well-pattern systems, distance between drilling slots, drilling and construction costs). Risk analyses of the threats and consequences involved in the process are performed, and risk-assessment matrices and mitigation actions are established. As a result, a model for selecting an optimal ITS for the Arctic/Sub-Arctic region is created. Some of the already-executed offshore projects (from Terra Nova and White Rose on the Grand Banks of Newfoundland in eastern Canada to Snøhvit in northern Norway) are followed by those still being prepared, such as Goliat and Skrugard in northern Norway. All these projects may be considered as true milestones toward oil and gas development in the Arctic region. Therefore, a review of these projects was performed while writing this paper to provide an important basis in experience. Because of this accumulated experience, we can turn future concepts into today's reality. This paper states important facts regarding ITSs and describes specific requirements for the Arctic environment. When dealing with operations in Arctic regions, a careful selection of installation vessels is very important; therefore, we present a short comparison of these vessels in a later subsection. Finally, because risk analysis must be performed before the start of any operation, a section regarding risk assesment is also included. This paper presents the analysis of ITS selection in three parts-- installation costs, construction costs, and total expenditures.
They are now becoming a reality, combining the design and installation of liquefied-natural-gas (LNG) units with a traditional floating production, storage, and offloading facility. Because FLNG facilities handle large flammable-gas quantities in a relatively small and congested environment compared with onshore LNG plants, the explosion risk is expected to be higher than that for some other offshore floating facilities. As a consequence, the intensity of the resulting blast loads on the unit can be more severe, even if the likelihood of explosion in the design is considered to be low through frequency analysis. Even if prevention and mitigation measures are implemented to reduce risk to as low as reasonably practicable, safety-critical elements (SCEs) such as main equipment and structures should be designed to withstand the blast event. Because the explosion events are very specific (high intensity and short duration), the common design rules and tools should be updated to take into account this accidental event. In addition, the associated performance criteria for SCEs should be modified. Finally, the entire design should comply with safety objectives (personnel protection, prevention of escalation). This paper focuses on the philosophy of design against a blast event on floating facilities in general, but with a particular focus on FLNG units. It will review the critical functions of the unit that must be maintained during emergency evacuation to protect people and identify the key parameters governing the explosion strength on floating facilities. It will show that the derivation of effective explosion loads on structures and equipment on the basis of computational-fluid-dynamics simulations is not straightforward and requires expertise in explosion modeling and explosion response. The paper will also show how all the engineering disciplines in Technip individually apply these blast loads in their designs through nonlinear-finite-element analysis. Finally, the paper will highlight the interface between the engineering disciplines and how a consistent demonstration through the design can be achieved to fulfill the safety goals, taking engineering further. Because FLNG is a new technology, there are neither design rules nor industry standards available for the explosion engineering of such facilities.
Hard substrates associated with offshore oil and gas platforms can contribute to the productivity of marine ecosystems, thereby generating local and regional economic benefits. These benefits form the basis for incorporating the platform into a rigs-to-reefs program when it is retired or for selecting some other type of removal option. There are many options for reefing platforms, each differing in environmental impact associated with dismantling and transport of the platform structure (deck, jacket, and other subsea structures). The use of science-based decision making in exploring platformremoval options can be beneficial for all stakeholders in the context of regulatory environment, complex ecosystem, and human interactions across multiple scales. Accommodating these complexities in a decisionmaking process is the foundation of an ecosystem-basedmanagement (EBM) approach. EBM is an environmental-management approach that recognizes the full array of interactions within an ecosystem, including humans, rather than considering single issues, species, or ecosystem services in isolation (Christensen et al. 1996; McLeod et al. 2005; Altman et al. 2011). The focus of this study is on one of Shell's former deepwater assets in the Gulf of Mexico. The fixed-jacket platform has been in operation for more than 35 years and extends to more than 1,000 ft of water depth off the coast of Louisiana. Few studies have been published on the ecology of marine life inhabiting deepwater platforms such as these. To begin to understand the specific contribution of this platform as an artificial reef, a stratified (across depth down the platform) study was performed by use of routinely collected remotely-operated-vessel (ROV) video footage to assess fish and sessile biotic communities. The ROV study revealed clear depth-related patterns of visually conspicuous epibiota (surfacedwelling organisms such as Lophelia pertusa) and numerous species of reef and pelagic fishes. These data were used to construct a matrix to rank the ecosystem services of several decommissioning alternatives, including complete removal of the deck and jacket; removal of the deck, topping the jacket 85 ft below the waterline, and leaving the remainder in place; and removal of the deck and transfer of the entire jacket to a rigs-to-reef location. This portion of the assessment provided a strategic framework for identifying and evaluating sensitive ecosystem services in association with both human and environmental drivers to provide realistic (actionable) guidance in the selection of these decommissioning options. The preliminary ranking illustrated that a high level of ecosystem services could be maintained by decommissioning alternatives that leave the jacket in place or transfer the jacket elsewhere as part of a rigs-to-reefs program.
An experimental study is conducted by use of a 6-in.-inner-diameter The experiments are conducted under low-liquid-loading condition, which is very commonly observed in wet-gas pipelines. The analyzed flow characteristics include wave pattern, liquid holdup, water holdup, pressure gradient, and wetted-wall fraction. Differential-pressure transmitters, a quick-closing valve and pigging system, and a high-speed camera are used to acquire the data. The trends of the data with respect to input parameters are investigated. The performances of commonly used models are compared with liquid-holdup, pressure-gradient, and water-holdup experimental results. The observed wave patterns include stratified smooth and stratified wavy with 2D waves, 3D waves, roll waves, and atomization flow. The transitions between the flow patterns vary as a function of water cut. The predictions of a transient multiphase-simulation software; the Tulsa University Fluid Flow Projects (TUFFP) unified model (Zhang et al. 2003), version 2012; Beggs and Brill (1973); Taitel and Dukler (1976); and Xiao et al. (1990) are compared with the acquired experimental data. The results from the transient multiphase-simulation software, Taitel and Dukler (1976), and Xiao et al. (1990) are in good agreement with experimental liquid-holdup and pressure-gradient data, but the three-phase water-holdup trends are not predicted well. The complicated nature of liquid/liquid interactions in three-phase lowliquid-loading flow causes greater uncertainties in predictions. The number of experimental three-phase data, especially with larger pipe diameters, is very limited. This paper provides comprehensive data for three-phase stratified flow for a 6-in.-ID In addition, the prediction performance of the commonly used predictive tools in the industry is provided. Low-liquid-loading flow is a flow condition wherein the liquidflow rate is very small compared with the gas-flow rate. It is widely encountered in wet-gas and gas/condensate pipelines. Even though the pipeline is fed with single-phase gas, the condensation of the heavier components of the gas phase, along with traces of water, results in three-phase flow. The presence of these liquids in the pipeline, although in very small amounts, can significantly influence flow characteristics such as pressure gradient and liquid holdup. Therefore, understanding of the flow characteristics of low-liquidloading gas/oil/water flow is of great importance in transportation of wet gases.