Ultra-deep Water Research Articles

Fatigue Reliability Analysis for Brace–Column Connection Details in a Semisubmersible Hull1

Semisubmersible floating platforms used in offshore deep or ultradeep water environments have hull structures that are comprised of vertical cylinders (columns) connected by braces, pontoons, etc. Several of the connections between these various members are susceptible to fatigue damage. In fatigue damage assessment or fatigue reliability analysis, a global structural response analysis is typically carried out using a finite element (FE) model where internal forces or stresses in the various members are evaluated for specified sea states measured at the site. Of specific interest in the present study is the fatigue reliability analysis of brace-column connection details in a semisubmersible hull unit for selected Brazilian environmental conditions. Stress concentration factors (SCFs) for the selected critical hot spots are applied to the nominal component stresses due to axial forces and biaxial bending. The hot-spot stress response spectra are used with various spectral methods—referred to as Rayleigh, modified Rayleigh (with bandwidth correction), and Dirlik—to estimate fatigue damage using Miner's rule. Uncertainties in some parameters used in the fatigue life assessment are considered and the probability of fatigue failure in the last operational year of the structure is estimated.

PVT behavior of methane and ester-based drilling emulsions

Abstract Well construction is especially complex in deep and ultra-deep water, where large Brazilian oil and gas reserves are located, demanding the use of synthetic-based drilling fluids, which have adequate characteristics such as lubricity, shale stabilization and low toxicity. Hydrocarbon gas kick will dissolve to some extent in any drilling fluid, but this effect can generally be ignored with a water-based drilling fluid. However, an operator working with synthetic-based drilling fluid must have training in gas solubility to avoid a blowout situation. Methane is the main component of natural gas, while ester can be used in the formulation of synthetic drilling fluids. To study phase equilibrium of these gas–liquid mixtures, at high pressures and high temperatures, found in bottom-hole conditions, specific, work and time intensive experimental tests were performed. The objective of this work is to present the experimental PVT data obtained from methane and ester emulsion mixtures. The fluid was loaded into a PVT cell and tests were carried out at desired conditions. Gas enrichment procedure was devised to cover temperature, pressure and methane concentration range with a long-term, single liquid amount test. Thermodynamic properties such as bubble pressure, solubility, density and formation volume factor of these mixtures were calculated up to 103 MPa and 130 °C, similar to bottom-hole conditions. A model based on the Peng–Robinson equation of state was used to predict the bubble point of the mixture.

Pipe technology and installation equipment for frontier deep water projects

Project perspectives in new offshore districts are targeting water depths of 3000–4500m in open ocean. Field development is often located in the proximity, not far from the toe of the continental slopes. In many circumstances the preferred option for exporting the products is the subsea pipeline, routed across the complex features of the continental slopes. Export pipelines from such fields are therefore large diameter pipes with thick walls to meet deep water strength criteria. Current projects show that material and linepipe technology are at the upper bound of what can be produced within the stringent criteria imposed by the application. Installation implies heavy lay spans that require large vessels as well as high capacity handling and pipe lay equipment. Specific upgrading of existing lay vessels cannot exceed certain limits and proven technology as high strength steel wire cables cannot implicitly provide adequate answers to the needs. Further, in case of huge fields, the development is progressive and the early pipelines include In-Line Structures that allow to accomodate future links to adjacent fields. The challenge is to lay along routes where features and bottom roughness require careful procedures to meet the established targets e.g. specific location of subsea structures in relation to pipeline alignment and their verticality.In this paper new solutions backed by advanced engineering tools are presented and discussed. Attention is paid to the installation of pipelines and heavy structures in ultra-deep water.

Ultra-deepwater blowout well control analysis under worst case blowout scenario

Because of the high frictional pressure losses in kill lines in ultra-deep water wells, it is challenging to control the blowout under worst case blowout scenarios. The operational parameters need to be carefully controlled to avoid exceeding the operational limitations such as breaking the formation or exceeding available pump pressure limit. In this study, dynamic kill simulations of multiphase flow are carried out to evaluate the operational parameters during the kill process. The simulations account for transient changes including frictional pressure losses, u-tube effect and fluid density variations. By optimizing the operational sequence with regards to, kill mud density, pump flow rate, pump down staging, relief well drillstring and trajectory, blowout can be controlled without exceeding the operational window. This paper shows that 10,390 bbls of the kill mud, 8000 psi pump pressure limit, optimum flow rate arrangement, and minimum 270 min required to get full kill mud return to the sea floor during the well kill operation. Through the aid of advanced transient software models, assessment of the required capacity to kill a blowout enables development of realistic contingency plans to ensure that well control can be re-established in case of an ultra-deep water worst blowout scenario.

Managing Marine Geohazard Risks Throughout the Business Cycle

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173139, “Managing Marine Geohazard Risks Over the Full Business Cycle,” by Andrew W. Hill and Gareth A. Wood, BP America, prepared for the 2015 SPE/IADC Drilling Conference and Exhibition, London, 17–19 March. The paper has not been peer reviewed. Today, the industry is faced with entry into frontier areas with little prior published understanding and potentially complex slope and deepwater settings. In such settings, early effort in the explorationand- production cycle is required to allow appropriate data to be gathered and assessed. In order to address these issues, BP has adopted a methodology to manage geohazard risks over the life of the license. Introduction In 1964, the rig C.P. Baker was lost in the Gulf of Mexico in a shallow-gas blowout with the loss of 22 lives. That accident, and similar events in the industry around the same time, triggered the development of geophysical site investigation or geohazard methodologies to support safety in tophole drilling and field development through detailed assessment of seabed and near-surface geology. To this end, the Hazards Survey in North America and the Site Survey in Europe became the staple means for evaluating predrill or predevelopment conditions over the following 30 years. The technologies used in these surveys have continued to be developed. These approaches have generally served the industry well for 50 years. However, as the industry has progressed from operations generally on the continental shelf out onto the continental slope and into ultradeep water, the geohazard issues that need to be addressed by the industry have grown in variety and complexity. While the scope of possible sources of geohazards has expanded, so has the potential size of license areas to be studied. If conditions across such blocks on the continental shelf or in ultradeep water were homogeneous, it may be acceptable to continue with the traditional approach of the site survey. However, the conditions in many large blocks are far from homogeneous, and, therefore, a site survey would deliver little understanding of the variability in geohazard conditions and processes that may have implications for the immediate safety of drilling. The longevity of production operations now faced in a license or field has also been gradually extended through the implementation of improvedrecovery techniques. BP’s Magnus field was discovered in the far north of the UK continental shelf in 1974. At the time of first oil in 1983, the projected field life was seen as being out to the mid- 1990s. However, another phase of production drilling will be starting from the platform in 2015, and current projected field life is now seen out to the 2020s. However, the last high-resolution seismic data to have been acquired below the platform were acquired in 1984. Before restarting drilling, a prudent operator would ask the question, “What is the possibility that geohazard conditions may have changed over the last 30 years?” The prudent operator, therefore, needs to revisit geohazard risks and the validity of site-investigation data across the full life of the license, from entry to field abandonment, and to update geohazard understanding consistently across the whole time period. This paper, therefore, sets out an integrated approach to address management of geohazard risks across the life of a license (Fig. 1), an approach that seeks to consistently update understanding of what geohazards might be present, and, thus, where possible, seeks to avoid them directly or mitigate their presence.

Technology Focus: Health, Safety, Environment, and Social Responsibility (August 2015)

Technology Focus If there is a discipline where current conceptual research and technology development expand simultaneously, involving highly interconnected people, it is health, safety, security, environment, and social responsibility (HSSE–SR, or HSE in brief). There are two reasons for that. The first one is the unique relationship between that discipline and society at large, which generates new challenges for or objections against the oil and gas industry every day. The second one is that the HSE discipline is rather young, compared with other exploration-and-production disciplines. Ten years ago, the challenge was almost technical only. As we were pushing back the frontiers (e.g., high pressure/high temperature, Arctic, ultradeep water, extraheavy oil, shale gas), we were striving to improve our HSE performances by reducing our footprint and the number of accidents, with a view to demonstrate to the stakeholders that providing us license to operate was both safe and the right choice for society. The paradigm has now changed. Is that because of the Macondo disaster and the release of the Gasland documentary film 5 years ago? Partly, but not solely. Stakeholder expectations are significantly different, and we now need to convince them of the rightfulness of our industry. Alternative sources of energy emerge and, like any newcomer, look like promising brides even when there are voices warning society about their latent defects. In the following pages, you will read of efforts made by the industry to develop tools to better understand the environment and the effects of the industry on it, to develop techniques to reduce or mitigate those effects, to find means to lower technical risks, and to ensure that every worker returns home safely every day. At the same time, there is an ongoing discussion on the best way to make progress, on how to influence the behavior of the workers, on how to maintain the competency of the workforce when experienced people retire, and on how to respond to the threats caused by new forms of violence. It is critical that our efforts continue, even in a time of depressed crude-oil prices. JPT

Effect of asymmetric boundary conditions on flexible pipes crushing

During installation, the tensioners of the pipe laying support vessels may impose asymmetric stress states on the inner carcass and the pressure armor of flexible pipes. Moreover, the possibility of admitting residual deformations in the cross section of flexible pipes after their installation is fundamental to allow the use of these structures in ultra-deep waters. However, these deformations are often not explicitly considered in predicting the collapse strength of these structures since the common practice is to consider symmetric stress states and collapse models with elliptical cross sections. This article thus presents a finite element approach that addresses the effect of asymmetric boundary conditions on the ovality of flexible pipes due to crushing loads. Their impact on the residual ovality in these structures after passing through the tensioners and the effect of these conditions on the wet collapse strength are also evaluated. By relying on the results from several numerical simulations, design strategies to address the asymmetric boundary conditions are discussed and a new methodology to measure ovality is proposed.

Technology Focus: Deepwater Projects (May 2015)

Technology Focus As the oil and gas industry pushes into deeper water, more-complex environments, and frontier unproduced areas, the technical and nontechnical risks related to appraisal and development of deepwater projects are likely to continue to increase substantially. While the technical challenges related to deepwater developments are significant— perhaps more significant and critical to the venture success—it is important that the nontechnical aspects of managing a new development in a frontier area be incorporated at the onset. After the successful discoveries in deepwater basins across the globe in west Africa, the North Sea, the Gulf of Mexico, Brazil, and elsewhere, operators are using the lessons learned and technologies developed in these fields to explore other frontier deepwater fields. The exploration in deep water becomes complex on the basis of various factors, such as water depth, geological formations, weather conditions, lack of oilfield infrastructure, and material and tools availability. The definition of deep water may vary with operators, but one definition of a deepwater field is any area of exploration where the water depth is greater than 150 m and there is a subsea blowout preventer. NORSOK defines deep water as water depth in excess of 600 m. Deep water may range from 600 to 3000 m, and ultradeep water is anything deeper than that. Deepwater operations create several additional challenges that need to be addressed in the design phase. Some of these, such as low temperatures at seabed, shallow flow hazards, and possible hydrates, are problems that are most commonly associated with deepwater operations. Other challenges, such as low fracture gradients and proper mud removal for cement placement and zonal isolation, are also common in nondeepwater environments; however, these become more complex, more significant, and more difficult to manage in deep water. There is no question that deepwater production will play a very important part in meeting the world’s future energy demand. The challenge for the oil and gas industry is to meet this demand safely, efficiently, and profitably. This is not an easy challenge in deep water, given the limited margin for error. The technical complexity and multibillion-dollar development costs require a robust development strategy that allows a project to deliver the promised value within the constraints of time. JPT Recommended additional reading at OnePetro: www.onepetro.org. OTC 25135 Deepwater Development Strategy by Martijn Dekker, Shell, et al. OTC 25443 50 Reservoirs, 48 Well Slots, and Two TLPs—Maximizing Recovery From the Deepwater Prolific Mars Field by Derek Newberry, Shell SPE 169245 Overcoming Ultradeepwater Cementing Challenges.in.the Caribbean by N. Gupta,_Schlumberger, et al. SPE 170286 A Novel Approach in Locating Single Loss Zone During Deepwater Drilling With Distributed- Temperature Measurement by Yuanhang Chen, The University of Tulsa, et al.

Calculation method of riser top tension in deep water drilling

Abstract Through mechanical analysis, a calculation method which meets the requirements of both the riser stability and the bottom over-pull margin was deduced. It was verified by an example of ultra deepwater well in South China Sea, and compared with two other common methods. Based on the related theories of pipe string mechanics, the effects of true axial force and effective axial force on the riser mechanical behavior were analyzed. The results show that, the bottom tensile force to Lower Marine Riser Package is determined by true axial force, and the riser's stability depends on effective axial force. Through the force analysis of riser which simultaneously bears the internal and external pressures, the correspondent mechanical model was established, and a new calculation method of top tension was derived, which remedies the deficiencies of algorithms proposed by American Petroleum Institute and Institute of French Petroleum. Field application shows that, the value of top tension calculated by this method is basically the same as the value set by field operation, and moreover, it is more accurate than the value obtained by the algorithms of American Petroleum Institute and Institute of French Petroleum. This method can be used to guide the design and operation of conductor.

Dynamic Positioning: Method for Disaster Prevention and Risk Management

The Offshore Oil & Gas industry, shipping and the ocean resource development industries play a vital role in the development of a country. The harsh marine environment and the need to explore for hydrocarbons in deep and ultra-deep waters has put in place technology and specialized marine support vessels to explore and produce hydrocarbons from below the ocean bed. The specialized vessels engaged in such operations have to maintain a fixed position in relation to a fixed point at the ocean bed despite the harsh vessel position deviating forces of sea currents, waves and wind acting on the floating vessel as little change in the position may lead to accident in the sea. So by the method of “Dynamic Positioning” the vessel is kept stationary in the sea and then oil and gas is extracted by using drilling vessels or drill ships. This method also allows other vessels like crane vessels, shuttle tanker, dredging and rock dumping vessels, pipelay, cable lay and cable repair vessels to remain stationary in sea so that extraction process takes place efficiently.

THE ELASTO-VISCOPLASTIC-TIME-DEPENDENT NATURE OF WAXY CRUDE OILS

Production in reservoirs located in deep and ultra-deep water that contain waxy crude oils faces a huge obstacle imposed by the low temperatures of the environment. When the waxy crude oil is subjected to a temperature below the Gelation Temperature, as in the case investigated in the present work, it exhibits a variety of non-Newtonian features: elasticity, plasticity, viscous effects, and time-dependency, which renders to this material a highly complex behavior. A crucial feature that is frequently ignored when the determination of the yield stress is being carried out is the timedependency nature of these materials. We demonstrate that this character has a significant impact on the measurement of the yield stress and, therefore, values obtained from a protocol that neglects time-dependency can be substantially different from a more careful procedure.

Deep-water riser fatigue monitoring systems based on acoustic telemetry

Marine risers play a key role in the deep and ultra-deep water oil and gas production. The vortex-induced vibration (VIV) of marine risers constitutes an important problem in deep water oil exploration and production. VIV will result in high rates of structural failure of marine riser due to fatigue damage accumulation and diminishes the riser fatigue life. In-service monitoring or full scale testing is essential to improve our understanding of VIV response and enhance our ability to predict fatigue damage. One marine riser fatigue acoustic telemetry scheme is proposed and an engineering prototype machine has been developed to monitor deep and ultra-deep water risers’ fatigue and failure that can diminish the riser fatigue life and lead to economic losses and eco-catastrophe. Many breakthroughs and innovation have been achieved in the process of developing an engineering prototype machine. Sea trials were done on the 6th generation deep-water drilling platform HYSY-981 in the South China Sea. The inclination monitoring results show that the marine riser fatigue acoustic telemetry scheme is feasible and reliable and the engineering prototype machine meets the design criterion and can match the requirements of deep and ultra-deep water riser fatigue monitoring. The rich experience and field data gained in the sea trial which provide much technical support for optimization in the engineering prototype machine in the future.

Uncertainty evaluation of wellbore stability model predictions

Abstract There is an increasing concern in the oil and gas industry regarding wellbore stability problems. The need to improve well operations becomes more imperative as the operators move towards more challenging and harsher environments such as ultra-deep waters and high-pressure and high-temperature (HPHT) fields. Different inconsistencies affect many previous wellbore stability analyses, resulting in incorrect results, or results that cannot be extended to other well configurations by well planners. Typical wellbore fracture and collapse models provide single point estimates of the geopressures. The model input data may be uncertain. Failure to capture these uncertainties has led to poor predictions. The purpose of this work is to investigate typical fracture and collapse models with respect to in accuracies in the input data with a stochastic method. Uncertainties in the input data, which include in-situ stresses, rock strength data, and pore pressure will be evaluated, to show how these contribute to the cumulative uncertainties in the model predictions. In this approach, the input parameters are assigned appropriate probability distributions. The distributions are then applied in the wellbore stability models. By means of Monte Carlo simulations, the uncertainties are propagated and the histograms of the outputs are generated. Two types of distributions – triangular and uniform – are applied, to see how the types of input-parameter distributions that are assumed influence the model predictions. Sensitivity analysis is also conducted. This is to ascertain the most significant input factors, which are largely responsible for the cumulative uncertainties or variabilities in the critical fracturing and collapse pressures. The proposed methodology can help in reducing many drilling problems such as circulation loss, stuck pipe, and well collapse. As a result, the industry may save much non-productive time. In addition, well planners will have improved information to make critical decisions.

Local dynamic buckling of FPSO steel catenary riser by coupled time-domain simulations

Steel catenary riser (SCR) is a popular/economical solution for the oil/gas production in deep and ultra-deep water. The behavioral characteristics of SCR have a high correlation with the motion of floating production facility at its survival and operational environments. When large motions of surface floaters occur, such as FPSO in 100-yr storm case, they can cause unacceptable negative tension on SCR near TDZ (touch down zone) and the corresponding elastic deflection can be large due to local dynamic buckling. The generation, propagation, and decay of the elastic wave are also affected by SCR and seabed soil interaction effects. The temporary local dynamic buckling vanishes with the recovery of tension on SCR with the upheaval motion of surface floater. Unlike larger-scale, an-order-of-magnitude longer period global buckling driven by heat and pressure variations in subsea pipelines, the sub-critical local dynamic buckling of SCR is motion-driven and short cycled, which, however, can lead to permanent structural damage when the resulting stress is greatly amplified beyond the elastic limit. The phenomenon is extensively investigated in this paper by using the vessel-mooring-riser coupled dynamic analysis program. It is found that the moment of large downward heave motion at the farthest-horizontal-offset position is the most dangerous for the local dynamic buckling.

ANN and wavelet network meta-models for the coupled analysis of floating production systems

This work presents the development of efficient meta-models based on Artificial Neural Networks (ANNs) and wavelet networks (WNs). The models can be associated to a coupled methodology for the analysis and design of floating production systems (FPS), providing fairly accurate results for the platform motions and the parameters of the structural response of the lines, with remarkable reductions in processing time.To accurately take into account the influence of the risers on the platform motions, previous approaches employing meta-models required the execution of coupled motion analyses, with the mooring lines and risers represented by Finite Element models; the resulting motions would subsequently be input to a meta-model for the uncoupled simulation of the line. Now, the model presented in this work will obtain simultaneously both the platform motions and the desired parameters of the response of the lines (i.e. any result that could be provided by a coupled FE simulation). This way, not only the FE structural analyses of individual lines can be avoided, but also the expensive coupled motion simulations, therefore comprising an even more rapid and effective computational tool.The performance of the ANN and WN meta-models are evaluated, in terms of accuracy and computational time, by their application to a FPS representative of those currently considered for ultra-deep water scenarios in Southeastern Brazil pre-salt fields.

Transportation Analysis of Dry Tree Semisubmersible

With the advancement of oil & gas into ultra deepwater, the need for drilling and production platforms has becomes more acute. The dry tree semisubmersible can be used for direct vertical access into reservoirs from deepwater since it offers small in-place motions, large open deck areas, dockside commissioning and minimum offshore hookup. The direct access allows the operator to drill, complete and work over the well directly from the same platform. The drytree semisubmersible consists of a keel tank which can be telescoped up and down based on the requirement of the platform. The keel tank is fully telescoped down while in operating condition and telescoped up while in transportation condition. The transportation analysis of a drytree semisubmersible using the linear radiation, diffraction panel program WAMIT is presented in this paper. Parametric studies were carried out in WAMIT by varying the size of the keel tank by considering the keel tank size as 80X80m, 91.5X91.5m and 100X100m. The Case 2 in which the keel tank dimensions were 91.5×91.5 m was found to be most appropriate of all, as the response for it was lower compared to other cases and also the structure was good from stability point of view. It was found that the heave and response were high only beyond 15 seconds wave period thus making transportation operations safe, as transportation is carried out in sea states 5 and 6 which have wave periods less than 14 seconds. Also the pitch RAO was found to be very low thus posing no threat in transportation mode.

Emerging Frontiers: Focus on the Subsea

President's column Over the past 6 months, I’ve talked about several emerging geographic and technology frontiers in the oil and gas industry. One of the most exciting and prolific emerging technology frontiers is also geographic in a way—the seafloor of deepwater basins around the world. Since the first installation of a subsea production tree in the Gulf of Mexico in 1961, the surge in the deployment of subsea wells has resulted in significant economic and environmental improvements in deepwater development. High oil prices, technological developments, and the need to counterbalance declining production in mature shallow-water basins have been driving the move of offshore oil and gas operations into deep and ultradeep (>10,000 ft) waters. Growth in this sector has been momentous over the past few decades. Subsea installations will grow from roughly 2,000 in 2001 to an estimated 8,500 by 2018. Growth in capital expenditure (Capex), driven primarily by Asia, Africa, and the North Sea is estimated to grow by 120% between now and 2018. Increasingly, operators are cost-effectively targeting reservoirs over a much wider area, tying back subsea wells both to fixed platforms in shallow waters and to floating infrastructure in deeper waters. In fact, capital-intensive ultradeepwater developments are expected to capture 48% of Capex and 23% of tree installations in 2014–2017, in contrast to 37% of Capex and 15% of installations in 2008–2013.

Technology Focus: Deepwater Projects (May 2014)

Technology Focus In the kingdom of wet completion, Petrobras has just installed its first tension-leg wellhead platform, in the field of Papa Terra in 1190-m-deep water. It is going to be a revolution regarding how to operate such an installation and be able to produce the heavy oil of Papa Terra (14–17°API). For many years, Petrobras engineers have being analyzing the use of a tension-leg platform or a spar as a solution for their field developments, and, finally, it came through. I strongly believe that all the lessons learned from installation (completed by now) to operation will result in much better solutions for the future of dry completion in our industry. In past JPT reviews, I wrote about the effect for field developments of the first floating production, storage, and offloading vessel in the Gulf of Mexico installed by Petrobras in Cascade and Chinook. And I believe that, once again, Petrobras is creating the same impact now in its own backyard. In February 2014, Petrobras reached a production of 400,000 B/D in the Brazilian presalt 8 years after of the discovery of the first field. In this presalt cluster, the consortium led by Petrobras, including Total, Shell, CNOOC, and CNPC, will be developing the Libra field, one of the biggest discoveries in ultradeep waters in the world. The estimated reserves of 8 billion to 12 billion bbl of recoverable oil will demand a great amount of resources to cope with the challenges of developing this gigantic field. If you are an engineer looking for an opportunity for technological growth and learning experiences, do not miss this chance. Lately, I have been reading a lot about the shale gas/oil developments in the United States, and I am amazed to see the forecasts showing that this gas/oil production will lead the United States to be self-sufficient by 2020 and a net exporter by 2030. It is a good example of what technology can do for you when combined with entrepreneurship. I have been reading also that unconventional oil and gas has taken money out of deepwater developments and that some majors have deferred their projects because of economics compared with tight oil projects. Equilibrium will come, and I believe both will contribute to our oil/gas supply. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 166337 Water-Depth Record for Electric-Line Operations—Retrieving Asphaltenes With Riserless Light Well Intervention by Steven Ashcraft, Anadarko, et al. OTC 24529 Roncador Module IV: A Successful Case in Heavy-Oil Projects In Ultradeep Water by E. Bordieri, Petrobras, et al. OTC 24508 Scale Management in Deep and Ultradeepwater Fields by M.C.M. Bezerra, Petrobras, et al.

Dual-Gradient Drilling in Ultradeepwater Gulf of Mexico

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166272, ’First Successful Commercial Application of Dual-Gradient Drilling in Ultradeepwater Gulf of Mexico,’ by Robert Ziegler, Mohd Saiful Anuar Sabri, and M Ramdan B Idris, Petronas, and Roar Malt and Roger Stave, AGR Enhanced Drilling Solutions, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. A previous attempt to drill an exploration well in ultradeep water in the Gulf of Mexico (GOM) did not reach its objective because of an inability to maintain a water-based-mud system light enough to maintain circulation. For the next round of exploration drilling, a controlled-annular-mud-level-type dual-gradient-drilling (DGD) system was applied successfully on this well in 2260-m water depth. This method compensates for the annular friction pressure by reducing the riser level according to the circulation pump rate. Introduction A specially designed drilling system was built for PC Gulf in 2011. This DGD system was to be used on Saipem’s Scarabeo-9 semisubmersible drilling rig. On the basis of experience gained with the previous offset well, Y-1, the system was considered a key tool to reach the planned total depth of Well C-1 by maintaining full mud returns should a narrow margin and a low-pressure scenario be encountered. Given the challenging metocean conditions in the area of operation, another major advantage of this deepwater managed-pressure-drilling (MPD) system is that the surface components of the riser system are not modified, so the weather capability of the rig is not changed, which often is a problem with rotating-control-device (RCD) -based systems. Also, because of the fluid level in the riser remaining unaltered by rig movements, there is no masking of influxes or losses by heave. Delivery of the DGD system to the Scarabeo-9 occurred in October of 2011, and installation and site-based commissioning took place while the Scarabeo-9 transited from Singapore to the GOM over a 2-month period. The system was first used on the J-1 well for another operator from mid-February to mid-May of 2012. Modifications as a result of lessons learned were implemented before spudding of Well C-1. DGD System This DGD system is designed for drilling post-blowout-preventer (BOP) sections. The system uses a subsea pump installed on a modified riser joint (MRJ) to manipulate the height of the drilling fluid in the riser annulus. By manipulating the fluid level in the riser, it is possible to alter the hydrostatic pressure seen by the wellbore, thus controlling the bottomhole pressure (BHP) while drilling. The DGD system’s effect is best compared to that of a conventional, RCD (backpressure) -based MPD system: While the RCD system virtually extends the height of a light fluid column by applying backpressure, leading to a steep mud-pressure gradient, the DGD system reduces the actual height of a heavier fluid column, which allows for a significantly flatter mud-pressure gradient much closer to nature. This leads to a significantly lower pressure exerted on the often weak casing shoe while maintaining the required pressure to control moveable formation content deeper in the drilled interval. For this specific operation, a three-stage subsea pump module (SPM) was installed on an MRJ to pump the mud returns back to the surface from a depth of 400 m. Fig. 1 presents a system overview. The MRJ was run as a single joint (50 ft) through the rotary table (the other joints were run as 100-ft doubles) without assistance from the DGD-system crew. After preparations were made in the moonpool (creating space among line cables and sheaves), operations to make up the SPM to the MRJ took place. Fig. 2 illustrates the MRJ being interface tested with the SPM onboard the Scarabeo-9 during transit.

E&P Notes (May 2014)

E&P Notes Fracturing by the Numbers: A Complex Balance For those in shale exploration, “fracability” is a real word, a critical property, and a point of contention. Fracability has entered the vocabulary of exploration because it is critical for exploration to know if rocks will produce when hydraulic force is applied. It can be a divisive concept, in part because there are a lot of ways to determine fracability, with dueling test methods and multiple equations offered by experts in petrophysics and geomechanics. A Lighter UltraStrong Proppant Oxane Materials has joined the 20,000 club—joining the two makers who have announced they are selling proppant capable of standing up to high pressures. The new offering, called OxThor, meets the standard set for use in frontier fields, such as those in the Lower Tertiary trend in the US Gulf of Mexico, where the grain-sized spheres will be called on to prop open fractures in wells drilled in ultradeep water that are around 30,000 ft deep. Carbon Dioxide Reserves Could Alter US EOR Map Growth in enhanced oil recovery (EOR) projects using carbon dioxide (CO2) in west Texas could be limited by supplies unless new sources of the gas are found in the ground or from industrial facilities. A recent report from the US Department of Energy (DOE) said that CO2 fields currently supplying west Texas, which has the largest concentration of EOR projects using carbon dioxide, can continue to produce at current levels for 10 to 20 years. That might be a constraint in an area where the number of potential projects could significantly increase demand. Colorado Emissions Control Rule Offers Some Flexibility Colorado will become a testing ground for reducing emissions from oil and gas exploration and production (E&P). A new rule, known as Regulation 7, is an early effort at reducing E&P emissions and may help resolve a contentious issue in a state that combines rich unconventional oil and gas resources and significant opposition to how they are developed. The addition of another regulation is not likely to be celebrated in the industry, but the collaborative process used to write the rule was praised by the head of one of the affected companies. “Hopefully, it is a new way to write a regulation,” said Doug Suttles, CEO of Encana, during his keynote address at the start of the IADC/SPE Drilling Conference and Exhibition in Fort Worth, Texas.