Subsea Completion Research Articles

System-Engineering Recommendations Aim To Improve Intelligent Completions

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209965, “System Engineering Recommendations To Improve Intelligent Completions,” by Ron Nelson, SPE, Consultant; Eric Handley, MacDermid Offshore Solutions; and Jonathon Joubran, SPE, Halliburton, et al. The paper has not been peer reviewed. _ The complete paper compiles recommendations from a broad range of sources into a single document to aid future intelligent-completion installations and operations. While emphasis is placed on subsea completions, these recommendations can be applied readily to differing well types. Important differences between production wells and injection wells also are addressed. Introduction Intelligent-completion interfaces span drilling, completions, facilities, production operations, and subsea-systems-engineering disciplines. Affected system components include the tree and tubing hanger, control system, control fluid, control lines, well fluids, well casing, downhole sensors, feed-through packers, and interval control valves (ICVs). Example diagrams are provided in Appendix B of the complete paper. While a successful intelligent completion can enhance a well’s value significantly, a failed intelligent completion can severely diminish that value, possibly rendering the well inoperable. Proposed Intelligent-Well-Design Process Control-Fluid Selection. The design process should start with the control fluid, which provides hydraulic force to open and close the ICV. It traverses the entirety of the system and will affect most system components. A successful control fluid will accomplish the following goals, which are further detailed in the complete paper: - Provide adequate lubricity - Maintain required properties across all design temperatures - Be compatible with all materials - Be compatible with completion brines - Provide adequate hydrate inhibition - Minimize environmental impact If the intelligent completion is to be installed in an existing development already using a fluid that cannot be used for the ICV, it may be possible to fill or “stack” the ICV lines with another control fluid that meets the downhole requirements and also is fully compatible with the in-service control fluid. The fluid’s original equipment manufacturer (OEM) should be consulted when a mixed-fluid system is considered. Assessing Thermally Induced Pressure Gains. Once a preferred control fluid has been identified, the next recommended step is to assess worst-case thermally induced pressure changes in the control lines. Thermal effects directly affect numerous intelligent-completion components. API SPEC 17D recommends keeping the tree-mounted ICV control-line isolation valves [tree-isolation valves (TIVs)] closed when not shifting the ICVs. At the other end of the control line, the ICV’s seals isolate the control fluids from the well fluids. Each downhole control line is a closed system when the TIVs are closed. A closed control line will behave like a casing annulus in that internal pressure will rise when warmed and fall when cooled. The pressure changes in the lines, however, can be far greater than those seen in the casing annuli and can affect the intelligent completion system’s pressure requirements profoundly.

Comparison of Raman, Brillouin, and Rayleigh Distributed Temperature Measurements in High-Rate Wells

With the maturity of and demand for fiber-optic sensing technology growing steadily over the last few years across multiple basins, operators are seeking fiber-optic sensing solutions that address the technology challenges associated with the life-of-field monitoring of subsea developments. Single-ended distributed temperature sensing (DTS) measurements have been acquired for decades now, typically using Raman optical time-domain reflectometry (OTDR) on multimode fiber. However, for topside interrogation of subsea completions, Raman DTS performs poorly. This is due to the available optical power budget and the potential wavelength dependency of optical attenuation across multiple connectors and splices comprising the optical subsea infrastructure. Any wavelength-dependent attenuation as the signals pass through connectors, splices, and optical feedthrough systems will generate step changes in the measured Raman DTS temperature profile. Brillouin OTDR can provide a DTS alternative that overcomes these challenges and operates on single-mode fiber. Brillouin OTDR operates with a large dynamic range to measure a wavelength (frequency) shift of the Stokes/anti-Stokes components that is proportional to both strain and temperature. Since downhole cables are manufactured with optical fibers suspended in a gel and with appropriate extra fiber length (EFL), any fiber strain relaxes, and the Brillouin wavelength shift is an absolute temperature measurement. An additional alternative is also explored here. We typically associate coherent Rayleigh OTDR with distributed acoustic sensing (DAS) on single-mode fibers, but low frequencies also contain a relative temperature dependence. The low-pass filtering of DAS data can then be used as a form of Rayleigh DTS with appropriate data processing. In this paper, we report on a comparison of Raman, Brillouin, and Rayleigh DTS simultaneously acquired in the same high-rate producer and injector wells. We validate that, with appropriate cable design, Brillouin DTS can be simultaneously operated on the same single-mode fiber with DAS and can deliver absolute temperature measurements suitable for production analysis. We also use a laboratory experiment to show that Rayleigh DTS provides an accurate measure of temperature changes comparable in precision to a traditional thermocouple. We conclude with a discussion about the implementation of this DAS-DTS solution for sensing subsea completions.

An evolutionary optimization approach to prevent electronics burnout in subsea oil and gas equipment

The electronics burnout in subsea engineering equipment caused by the excessive heating of electronics due to improper cooling mechanism is an area of major concern in subsea oil and gas fields. Very often the electronic canisters are encapsulated by insulation to prevent hydrate formation in the subsea completion equipment. The electronic equipment with a set of sensors is usually deployed subsea for live monitoring of data and to regulate the functioning of the equipment. This study presents a numerical methodology to predict and prevent electronics burnout in a pressure/temperature transmitter (PT/TT) that is truly representative of a wide class of PT/TT deployed subsea. An optimization study of the insulation system around the PT/TT sensors that encompasses the various contradicting constraints that are routinely encountered in subsea engineering has been presented for the benefit of the readers. In the present study, the optimal design of the insulation system around the electronics equipment is generated using a combination of thermal finite element analysis and evolutionary optimization algorithms. The results obtained show that the proposed methodology can yield results which could be a tremendous improvement in the traditional means of designing the insulation systems for such electronics equipment. It is also shown that locating the electronic housing far from the production fluid in the PT/TT sensors can lead to proper cooling and thereby avoid the burnout to a significant extent.

Guest Editorial: The Future of Subsea Well Access and Completions

Guest editorial A review of technologies currently applied in offshore environments to drill and complete subsea wells for hydrocarbon production confirms that many opportunities exist to improve methodologies in ways that can be more economically beneficial and more environmentally sustainable. Most drilling and completion challenges have been met and overcome on a case-by-case basis although collective knowledge, and industry improvements, have progressed rapidly since the late 2000s. Subsea completions for gathering hydrocarbons from subsea wells have demonstrated both environmental and economic benefits for offshore oil and gas projects. Barriers and opportunities for expanded use of subsea completions involve both technological and regulatory issues. Advanced technologies are needed to ensure long-lived and serviceable subsea•equipment. Reasonable regulations also are needed to make sure that the best available technologies and practices are considered in•rulemaking that affects subsea operations and future of subsea well access. Well Completions and Subsea Completions Completion is used in offshore oil and gas activities in two different contexts. A well completion involves a set of actions taken to convert an individual borehole into an operational system for controlled recovery of underground hydrocarbon resources. A subsea completion refers to a system of pipes, connections, and valves that reside on the sea floor and serve to gather hydrocarbons produced from individually completed wells and direct those hydrocarbons to a storage and offloading facility that might be either offshore or onshore. Subsea completions typically contain an upper completion, a lower completion, and a production tree. Advances in upper and lower completions followed normal developments in materials, pressure, and temperature ratings. However, significant advancements in subsea well access has occurred in the past few years. The later advancement reduced operational costs and led to the capability to develop one-trip, single-system, umbilical-less installation of tubing hangers. One of the remarkable accomplishments of the upstream offshore petroleum industry has been the development of technology that allows simplified but efficient subsea well access to carry out the operations in a more complex situation. Despite an increase in complexity, improvements in subsea well access and completion technology have allowed more complex well patterns to be drilled to a greater depth such that additional hydrocarbon resources can be developed at a greater distance from the drilling or production structure, allowing more energy to be produced with less environmental impact. In the past 15 years, mechanical subsea systems have been developed, which allow deepwater riserless drilling with weighted mud and with fluid returns to the drilling rig. Those systems allow a dual-gradient hydrostatic pressure to be applied, thereby more closely matching the natural deepwater pressure profile. While those systems have been used on a number of offshore wells, there is limited supply of the necessary equipment and other well-control issues must be carefully considered for each particular operation.

Increasing Efficiency, Safer Operations Key Themes at OTC

Conference review - 2016 OTC Despite the downturn in the oil and gas industry, more than 68,000 experts and leaders gathered from across the world in Houston for the 2016 Offshore Technology Conference (OTC) in May. The number of attendees, from 120 countries, put this year’s OTC among the top 15 in attendance in its 48-year history. “As it has since 1969, the world came to OTC to make critical decisions, share ideas, and develop business partnerships to meet global energy demands,” said Joe Fowler, 2016 OTC chairman. The conference included 11 panel sessions, 24 executive keynote presentations, and more than 325 technical paper presentations. Increasing efficiency while ensuring safe operations was a key theme at this year’s conference. Sessions covered new technologies that not only reduce costs to the operator but enhance the overall safety of the operations; cost-effective advances in well cementing technologies; and use of RFID to precisely track drillpipe. Subsea Processing Panel sessions covered a variety of industry issues, including the value of subsea operations. Moving oil/water separation equipment from platforms to the seabed looks inevitable, but based on the current rate of adoption, it may require a long-term outlook. Out of the 5,000 wells with subsea completions, only five have used some variety of separation, whether it is separating water from oil, gas from liquids, or treating seawater before it is injected into a reservoir. A panel made the case for why separators are a better option in deep water than lifting water a mile or more, processing it, and pumping it back down to the bottom for injection into the ground. “It is going to happen,” said Jeff Jones, senior subsea systems consultant for ExxonMobil. “We will get back to it.” Jones referred to subsea separation in the past tense because it has been a while since the five projects, eight if you include some smaller units used for pilots, have gone into service. “It is not as dead as you think,” said Don Underwood, director of subsea processing for FMC Technologies. “We are in a world where, perhaps, operators cannot go forward with green-field projects,” but still need to find ways to add production to make up for declines in older wells. As for what will turn the inevitable technology into a practical option, the one-word answer is cost. Statoil, which has been a major supporter of moving operations subsea, has said that a 50% cost cut is needed, while Petrobras has put that number at 30%. “There has been significant movement in that direction,” Underwood said. “For one, prices have been lowered dramatically,” while designs have shifted from huge units to “lower-cost, compact technologies” that can be added as a cheaper alternative to drilling.

Technology Focus: Wellbore Tubulars (June 2016)

Technology Focus Today’s economic situation within our industry has been harsh, harder than any downturn I have witnessed during my 44 years in the industry. However, it has provided the environment to influence positively the forging, application, field trialing, and acceptance of innovative technologies within our industry. Recent oil-industry technical publications are filled with a wide variety of applications of models, tools, and techniques being developed and applied to the drilling, completion, intervention, and even wellbore-abandonment arenas, allowing us to be more efficient by driving costly nonproductive time out of our operations. While the development of innovative technologies is critical, their correct and cost-effective application is even more important. No matter how good, technically impressive, or even innovative a technology is, if its application is not operationally practical as well as cost-efficient, then in the end it is just a cute widget. The papers within this Wellbore Tubulars section focus on delivering efficiencies to us, converting nonproductive time into new dollars for the bottom line. These papers span the application of A 1000-m steerable drilling liner directionally drilled in through an unstable shale in the åsgard/ Midgard field in the Norwegian North Sea after multiple attempts to drill and case this same hole section failed. A subsea completion string that would provide efficient hydraulics during fracturing operations while ensuring mechanical and pressure integrity. This high-pressure/high-temperature system was developed to be the answer to extreme completion challenges within multiple deepwater Gulf of Mexico projects within the Jack and St. Malo field reservoirs. A drilling software that delivers operational surveillance in real time, assisting in the avoidance of stuck pipe and with application within a variety of drilling environments. The proposed software was tested with historical data sets from 36 stuck-pipe incidents in the Eagle Ford, Utica, Permian, and Gulf of Mexico. The paper contains discussion of case histories in several shale horizontal unconventional wells. The extended-reading references selected further explore various applications and evaluation techniques spanning tubular-application areas from completion intervention to casing remediation to drilling-challenge mitigation. These include case-history references to assist readers in expanding the applications knowledge within their wellbore-tubulars toolbox. We all strive to deliver quality well construction, production, intervention, and abandonment to our industry. During the evaluation of the writings to be included within these few short pages encapsulating the extensive base of information published that surrounds the application of wellbore tubulars, I was struck by the quality and diversity of information available. Therefore, the reader is encouraged to search further within the industry’s technical-paper and article archives in the OnePetro online library (www. onepetro.org) to explore additional aspects of wellbore tubulars and the tools and techniques that are currently available to responsibly apply and critique their applicability. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 175878 Steerable Drilling Liner Matches the Industry’s Common Theme Regarding Cost-Optimization Approaches and Minimizing Geomechanics-Related Challenges—Technology Overview, Applications, and Limitations by Wael El Sherbeny, Baker Hughes, et al. SPE 168271 Tubing-Retrievable Surface- Controlled Subsurface-Safety-Valve Floating-Flapper Remediation by B. Gary, Halliburton, et al. SPE/IADC 178780 Solid-Expandable Solution To Qualify Existing Nonsour- Service Production Casing by Jesus D. Contreras, ConocoPhillips, et al.

Pressure Test for E&P Innovation

Oil prices are so low that the oil industry is having to consider doing things differently. It is a hopeful sign for the future for innovators who have been struggling to keep going and have potential customers with little to spend and a lot to worry about. “What we see is a lot of consolidations and slowdowns now. A lot of risk-averse folks out there who do not know if their companies will survive from one day to the next,” said Chuck Matula, who is a board adviser and founder of a company called Drill2Frac, which offers services aimed at unconventional producers. “2015 was an absolute blur. Absolutely everyone was trying to keep an oilfield operation afloat, there was so much indecision and uncertainty,” Richard Broderick president and chief executive officer (CEO) of Fountain Quail Water Management, said during a session at the recent IHS CERAWeek conference in Houston. Demand for the water company and others has slowed as drilling and completion work plummeted in shale fields where the cost of adding production exceeds the price of oil, which dipped below USD 40/bbl in early April. Those still on the payroll have powerful motivation to consider how to reduce operating costs or increase production enough to pump profitable barrels if oil edges toward USD 50/bbl. Those with likely answers to that question “were getting some traction when prices where high, but not as much as they are now,” said Vikram Rao, executive director of the Research Triangle Energy Consortium. Sales are limited because “they can only make that point to survivors.” Rao divides the market into three groups based on their financial needs. At the top are the companies with secure financial futures—the majors and the strongest of the independents— and at the bottom are those in serious financial trouble. The rich have resources to spend, though it is limited by their drive to reduce costs; but their survival is not at stake. That is the issue for companies at the other extreme, which have no money to spend because they are focused on dealing with creditors. In the middle are those companies with some money to spend and a great sense of urgency. Their long-term future depends on quickly lowering their cost per barrel enough to survive with oil selling for less than USD 50/bbl. And they will not be able to get there by squeezing suppliers for more discounts. “What is happening is, basically, innovate or perish for anyone in between,” Rao said. “They have 2 years to show they can survive, and 3 years to make good.” “They cannot keep doing things the same way and they are looking for new solutions,” said Mark Wilkinson, a vice president for GroundMetrics, which is trying to convince companies that they can better understand what is going on in the ground by using electromagnetic imaging to track water and carbon dioxide flooding, or spot missed oil reserves. Faced with similar cost pressures, and an equally awful economic environment in the 1980s, Rao said operators did manage to quickly reduce the cost of production, frequently employing innovations from the service sector. The industry embraced 3D seismic, subsea completions, horizontal drilling, and logging while drilling (LWD).

A Remotely Controlled Downhole Valve Used for Completion Installation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166271, ’A Case Study of Using a Remotely Controlled Downhole Valve for Completion Installation,’ by Keith Oddie, SPE, and John O'Hara, SPE, Halliburton, and Luis Paz, SPE, Hess Corporation, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. On the basis of a case study in Equatorial Guinea, this paper demonstrates how barrier provisions with remotely controlled open/close technology capabilities enable interventions to be removed from a completion design. The technology described was used in a horizontal subsea producer well drilled to 3460 m. The paper will illustrate how combining downhole electronic control with a full-bore hydraulically operated barrier valve removes any need for running control lines to the surface. Surface-applied pressure and time combinations were used to command remote actuation of the valve. Introduction The Ceiba field is located 35 km offshore Equatorial Guinea, west Africa, and is 241 km south of the capital, Malabo. Located in approximately 700 m of water and in one of six subsea clusters in the development, this well was identified as a suitable candidate for inclusion of the technology outlined in this paper. To maximize reservoir recovery in this field, the completion strategy included a horizontal openhole gravel pack to provide downhole sand control. The completion engineers felt that this strategy would help meet production objectives such as inflow performance. However, it would also require the well to be drilled at a highly deviated trajectory, which would increase the likelihood of the production packer being set at a deviation beyond conventional slickline capability. The remotely controlled downhole valve offered an alternative plugging method to set the packer, test production tubing, and commission subsurface well-control equipment requiring well interventions, and therefore was included for consideration in the well design. The well design would later confirm that the valve would be installed at a deviation greater than 70°. Plug deployment with wireline and tractor was evaluated in terms of risk and exposure to cost, and from the results of the evaluation, it was concluded that remote technology should be included in the basis of design. A landing-nipple profile located below the packer provided contingency in the event that the remotely controlled valve failed to close. The final subsea completion design required that the 547-m reservoir section be drilled along a horizontal trajectory, the openhole horizontal gravel-pack system be installed, and the gravel pack be performed. Retrieval of the gravel- pack service tool and wash pipe would mechanically close the fluid-loss control valve to provide isolation from the reservoir during deployment of the upper completion. It would also provide a means of applying the pressure and time signature required to close the barrier valve.

Technology Focus: Subsea Technology (August 2014)

Technology Focus Subsea processing is an enabling technology for deepwater-oilfield development. The primary technologies of interest are fluid separation and pumping. There are also many supporting technologies that must be targeted toward subsea processing, such as flow assurance, controls, power distribution, performance monitoring, maintenance and repair, high-integrity pipeline-protection systems, and high-pressure/high-temperature technology. Subsea processing is a significant technology that presents and will continue to bring many challenges and opportunities to the industry. Can we safely and economically move traditional field-processing equipment from the surface to the ocean floor? There is a strong incentive to eliminate (or greatly reduce the size of) surface-supported processing facilities; they are expensive and heavy, they can certainly be the long-lead item on a schedule, and they are susceptible to environmental (weather) effects that will affect operations. The biggest advantage to surface processing equipment is that “I can walk up to it and touch it.” Is that advantage worth the cost? This is the starting point for considering subsea processing. We can compare the development of subsea-processing technologies with that of the more-traditional technologies such as subsea drilling and subsea completions. With 40 years of history, the industry has become comfortable enough with subsea drilling and completions that these technologies have become comparatively standardized, routine, and predictable. The equipment designs for subsea wells, trees, manifolds, and distribution systems have matured, which has reduced the perceived and real risks of subsea field development. This, in turn, has allowed asset owners to forecast development cost more predictably and accurately, which has encouraged subsea investment. We have all heard the lament, “I could sure use that technology, but I cannot take the risk of being the first one to use it.” Risk reduction has been the key to success for subsea completions. Risk reduction has largely occurred over time by the increasing number of installations, which has led to design improvements through installation and operational lessons learned. The engineering challenge before us is to reduce, mitigate, and eliminate the risks associated with the new technologies. This allows asset owners to justify the incorporation of the new technologies of subsea processing into their projects. The risk categories that must be addressed successfully are safety, quality, and commercial success. There have been some great successes, some of which are discussed in the following papers. However, there are still many things to be learned. The next generation of engineers will face exciting challenges in bringing these technologies to the market and maturing them to a level of acceptance that we now realize with subsea-completion technologies. I envision that subsea processing will serve as a springboard for new enabling technologies that have yet to even be considered. It will certainly be interesting to watch the continued development and maturing of subsea processing and the associated technologies. JPT

Feasibility Study and Economic Analyses for the Marginal Field Development Using Proxy Models under Uncertainty of Reservoir Characterization

Economical development of marginal fields is one of the key issues for the oil & gas industry. Risk analysis and optimization technique can be applied to ensure the economics of E&P projects in terms of the development scenarios, cost optimization, and production schemes. Depending on the reliability of reservoir data and the easiness of development, a field operator can exploit the whole field at the same time or choose a phased development strategy. Especially for a basement fracture reservoir, which has high uncertainty in connectivity among fractures, it is better to develop and produce oil from more reliable part of reservoir and then extend to the remaining parts. Even through this strategy, it is often necessary to face the difficulty in the determination of the proper development concepts such as a separate wellhead platform or sub-sea completion. The number and locations of wells also should be optimized to increase the net present value of the project. This paper presents a workflow to determine the development feasibility of oil and gas fields under the uncertainty of reservoir characterization using the neural network and Monte-Carlo simulation. In this paper, we focus on the evaluation of risk and uncertainty of a project's economics under the uncertainty with the connectivity of main producing area and the remaining area. Through the application of the proposed method to a real field in Vietnam, we show that the connectivity between adjacent areas in the basement reservoir is critical to estimate ultimate recovery and to evaluate the project economics. The production incremental through the development of the remaining area will be mainly affected by the production of the existing wells depending on the connectivity. From the evaluation of net present values according to the development concept and the schedule, this paper shows that the project's economics can be improved and better bases for decision making can be provided.

Innovation: Innovations in Subsea Completions

President's column The demand for more and more oil and gas has prompted the industry to seek new areas of hydrocarbon deposits, and the development of subsea completions has kept pace. Many huge innovations have taken place since the first underwater completion was made about 70 years ago, when the first wet wellhead, basically a land Christmas tree, was deployed in shallow water. Finding hydrocarbons in deeper and deeper waters, away from existing infrastructure, has prompted the need to complete wells on the sea floor and then pipe production to floating facilities. The depth of water in which these wells were drilled made the use of platforms become technically unfeasible or not supportable by the economics of the development. The North Sea, Gulf of Mexico, Brazil, and west Africa have been the major areas of subsea development and reserves in increasing water depths have been brought into production, and more recent finds in east Africa are yet to be developed. New technology has been deployed in a number of areas (Vernotzy 2013): Drilling rig and equipment design capable of operating in water depths in excess of 3000 m Better understanding of weather, ocean, and seabed conditions Flowline and pipeline design and deployment Design of very reliable processing and control systems The development of sophisticated remotely operated vehicles (ROV) A recent study (Nelson et al. 2013) to review and understand where oil and gas has been found recently revealed the following. Globally, deep water has become a significant source of discoveries, accounting for more than 50% of new conventional reserves. The size of deepwater discoveries is an order of magnitude larger than other discoveries. However, less than 40% of those discoveries are in production, contributing less than 10% of conventional production. Deepwater production could double in the next 7 years as more fields are brought into production. Early deepwater development required the use of proven technology, innovation, commitment, and teamwork between license holders, equipment suppliers, and service providers. Given the depth, it was essential that equipment be designed to operate at a very high level of success. Over the years, subsea completions have become more complex, varying from single wells connected to a platform to subsea “factories” consisting of an array of wellheads, manifolds, and processing equipment. Irrespective of the complexity of seabed configurations, the fluids produced will have to be channelled to an onshore handling facility or to a fixed or floating processing unit. Given the environment under which the installed equipment has to operate for long periods of time with minimum intervention, the equipment must be robust and reliable and must ensure safety for personnel and protection of the environment.

Reducing the Hidden Costs of Subsea Well Completions

Subsea completions have made it possible to produce oil in remote locations and from smaller reservoirs. But the cost of maintaining them may shorten their productive lives. “Subsea wells have the same things that go wrong as other wells, but fixing them requires moving in a rig and the cost can often be USD 1 million a day,” said Matthew Law, technical manager of sales and marketing at Expro Ax-s Technology. “Where there is direct access from a production platform, there is generally regular well intervention. As a result, the recoverable reserves are higher.” Major producers such as BP, Chevron, ExxonMobil, Statoil, and Shell are among those seeking to cut the cost of deepwater workovers by 50% or more to allow better maintenance. There is no accepted industry average for how much production can be gained from regular interventions. The consensus is that the potential impact on the thousands of subsea completions represents billions of dollars worth of hydrocarbons. “One of the biggest challenges in (increasing) deepwater recovery rates is the cost of re-entry is so high,” said Peter Sharpe, executive vice president of wells at Shell. Drilling rigs are capable, but it can cost USD 5 million to just diagnose why production is down on a subsea well. Based on offshore workovers generally, the payoff for deepwater work will range from simple fixes that yield significant gains, to difficult cases where the repair cost far exceeds the likely return. Most wells fall somewhere in between. The experience of operators in the relatively shallow waters of the North Sea shows there is a return for investing in regular subsea well maintenance. The cost and technical challenges rise in deep water, where the lower-cost methods used in the North Sea are now being tested. Without significant cost reductions, the cost of repairs that can slow production declines on 10 wells can exceed the cost of a deepwater exploration that might deliver far more in the near term. To reduce cost, the industry is considering a mix of proven technologies and emerging ones. Much of the work is directed toward using construction boats rather than drilling rigs. “Cost is one of the drivers, but we are also looking at keeping these activities off drilling rigs to allow more exploration and development work,” said Colin Buchan, well delivery manager for floating hoist at Shell. “They are complex machines designed to drill wells. They were not designed for well interventions.”

Planning and Execution of Highly Overbalanced Completions From a Floating Rig: The Ursa-Princess Waterflood Project

Summary The Ursa-Princess Waterflood (UPWF) targets the Lower Yellow sand, the main reservoir in the Mars-Ursa basin in Mississippi Canyon, approximately 60 miles south of the mouth of the Mississippi River in the Gulf of Mexico (GOM). The Lower Yellow sand, a world-class Upper Miocene turbidite reservoir, has been on production in the Ursa and Princess fields since 1999, and has been drawn down nearly to the bubblepoint. The waterflood is intended to increase and stabilize reservoir pressure, and to improve sweep efficiency. To accomplish this, four subsea injectors were designed and constructed to inject treated seawater at 40,000 B/D each for a target life of 30 years. Because the Lower Yellow reservoir was already highly depleted, unique risks were identified in the planned subsea completion operations, to be conducted from a mobile offshore drilling unit (MODU). Seawater, used as a completion fluid, was expected to be up to 4,000 psi overbalanced to the reservoir, depending on the well location. This created the risk of either an uncontrollable fluid-level drop in the marine riser or an extreme impairment to the sandface completion. In order to maintain well control with a fluid level at the surface and still deliver low-skin completions, multiple design and procedural issues needed to be addressed, including the following: Control systems on the rig and riser system to prevent uncontrollable fluid-level drop. Perforating systems to minimize impairment in a highly overbalanced environment without adding undue risk to well control. Pill designs that could both control fluid loss at the sandface and clean up effectively. Downhole completion systems capable of functioning either under very high pressure differentials or against very high loss rates. Development of high-burst screens suited to the use of fluid-loss-control pills as a contingency provision in the event that mechanical fluid-loss devices failed. As more deepwater reservoirs approach depletion, specialized tools and procedures will be required to continue to deliver safe and effective sandface completions from floating rigs. This paper details many of these considerations and summarizes the execution experience and results for one such reservoir.

Growing Offshore Water Production Pushes Search for Subsea Solutions

There are strong arguments for moving water processing from deepwater platforms to the seafloor in many fields. There need to be, given the daunting challenges to doing so. One of the prime targets is older offshore fields producing more water than oil. When the water treatment facility on the topside reaches its capacity, it puts a cap on oil output. The rising water cut increases the force needed to lift a production stream holding ever less oil, as the pressure in the reservoir declines. Ultimately the natural force isn’t enough to lift the water and oil from deepwater fields, which will mean the end of production if nothing is done. “When you can’t get it to the surface, you are left with nothing, unless you have got a way to pump it,” said Tim Daigle, senior project engineer at Fluor Offshore Solutions. There are two ways to do that: Increase the lift with pumps, or reduce the load by removing the water on the seafloor and disposing of it there. After nearly two decades of development and testing, the latter option is beginning to emerge as an alternative. Oil companies are turning to subsea processing for projects that are challenged by the economics, looking for ways to make them profitable, or to improve their results, said Mike Robinson, a sales and marketing manager at FMC Technologies, which is a leader in this area. Statoil’s Tordis field offshore Norway shows the upside and downside of subsea water separation. The company predicted the combination of subsea water processing and improvements in the pumping system on its Gullfaks C platform would increase ultimate production by 35 million BOE, pushing the field’s recovery rate from 49% to 55%. The design is based on what Statoil learned from its earlier pilot test installed on its Troll C platform in 2001, which is still processing 50,000 bbl a day and reinjecting the water into an aquifer. Rune Ramberg, chief engineer of sub-sea technology at Statoil, said there are many reasons for the Norwegian company’s push to develop subsea water treatment systems. It has long relied on subsea completions. Developing Arctic resources will require alternatives to offshore platforms, which are vulnerable to ice. And most importantly: “We are not making money transporting water,” Ramberg said.

Congo FDPSO An Industry First

Off the coast of the Republic of Congo and at water depths of 1400 m (4,600 ft), the Azurite field began production in August from a unique facility, the industry’s first floating pro-duction, storage, and offloading vessel with drilling capacity (FDPSO). Touted as a cost-efficient solution for drilling and producing deepwater fields, the Azurite FDPSO allows vessel owner Prosafe Production and operator Murphy Oil bragging rights for developing an installation that many in the industry had seen as economically unsustainable. The unit is equipped to process 60,000 BFPD and 40,000 BOPD and store approximately 1.3 million bbls of crude at full production, in a manner similar to a traditional floating production, storage, and offloading (FPSO) vessel. However, it is also able to drill wells without the need for other drill-ing vessels such as mobile offshore drilling units or jackup rigs. While the concept of an FDPSO has been known for decades, the launch of the Azurite marks the first time that the concept has become a reality. Making this possible required a concerted team effort between Prosafe, Murphy, their various engineering and equipment providers, and classification provider Det Norske Veritas (DNV). Field Development Evolves The Azurite field, which is located in the Mer Profonde Sud block approximately 150 km off the coast, was discovered in 2005 and marks Murphy Oil’s first operated development in west Africa. Murphy was keenly aware of the need to choose a production option that would maximize recovery of the field’s estimated 70 to 75 million BOE recoverable reserves while also keeping costs to a minimum. The initial development plan called for the subsea infrastructure to link to an FPSO, a scenario that had been successful in the region and at similar water depths. Murphy submitted a bid package in June 2006 to vessel providers for the conversion and delivery of an FPSO, at this point without any provision for a drilling component tied to it. However, even at this stage Murphy was considering the feasibility of adding a drilling package to an FPSO—driven primarily by the expensive market for drilling rigs. “We were trying to figure out the best development scenario given our reserves position,” said Ken Hampshire, Azurite field development manager for Murphy Oil. “Other development scenarios, including spars and tension-leg platforms, required a great deal of drilling capacity that had to be brought in independently of the production facility. “Even the FPSO option did not solve our drilling-management challenges, and at the time rig rates were extremely high,” Hampshire said, quoting daily rig rates of USD 500,000 and higher. “If you add all other costs associated with securing a rig capable of performing subsea drilling and completions in 5,000 ft of water, you’re faced with costs in the range of USD 750,000–800,000 per day.”

Santos Basin Presalt-Reservoirs Development

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19953, "Santos Basin's Pre-Salt Reservoirs Development - The Way Ahead," by J.M.F. Filho, SPE, A.C.C. Pinto, SPE, and A.S. de Almeida, SPE, Petrobras, originally prepared for the 2009 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed. The full-length paper describes the current studies for the future development of the presalt reservoirs in the Santos basin presalt cluster in deepwater offshore Brazil. Development of the area is divided into three phases. The first phase is a dynamic information-gathering phase comprising extended well tests and production pilots. The second phase, extending to 2017, will comprise conventional subsea completion systems. The third phase will consider nonconventional solutions. Introduction The area known as the presalt cluster, in the Santos basin, is in ultradeep water between 1900 and 2400 m, approximately 290 km offshore the Rio de Janeiro coast in southeast Brazil. Fig. 1 shows the main blocks of the presalt cluster, currently in the appraisal-plan phase. At the beginning of the current century, the "cluster blocks" in the Santos basin were considered one of the most important exploration frontiers of the Brazilian continental shelf, given the size of the structures and the perfect seal created by the salt layer. In 2002, as the operator of different consortia, Petrobras obtained, through a bid process, the concession to explore several blocks in the Santos basin area. The first location, known as Parati (RJS-617), was approved in March 2004. At that time, just two wells had been drilled in the proximal portion of the basin, having crossed thick intervals of the presalt section. The existence of source rocks with characteristics similar to those found in the Campos basin was inferred through geochemical correlations, but there was significant uncertainty regarding the maturation, migration, and volumes that could have been generated and trapped. Despite these uncertainties, the most important risks associated with the locations were related to the existence and quality of the reservoirs. The Parati location was intended to test the stratigraphic traps in multiple objectives in the post-salt section and, additionally, to test a domic structure in the presalt. The sandstone reservoirs above the salt contained water, and the decision was made to go ahead with the well. After drilling 500 m of basalt, with several operational problems, the well drilling stopped at 7600 m true vertical depth subsea (TVDSS). Gas condensate was found in reservoirs of the presalt, confirming the presence of a petroleum system in the area, stimulating the drilling of RJS-628 in the presalt, which resulted in the Tupi discovery.

A Novel Technique for Determining Sand Screen Failure

Summary Offshore completions in the Gulf of Mexico (GOM) must typically address sand control. Our industry has made significant progress with respect to sand control equipment and implementation. However, all methods of sand control are subject to mechanical failure, with the first indications often being the production of solids into a common separation facility. In many offshore completions, particularly subsea or multizone completions, it is often difficult and expensive to determine which well or specific completion interval has failed, most times requiring production to be shut in for diagnosis. Not until that point can a remedy be evaluated. One GOM producer engaged the services of a proppant supplier to determine whether or not a suite of proppants/gravel can be developed that uniquely identified and placed in each completion interval. In the event of proppant production to surface (i.e., mechanical failure), the surface samples are analyzed to directly determine which interval failed. The proppant needs to be nonra-dioactive, yet identifiable with standard laboratory techniques. The supplier subsequently developed a methodology whereby the proppant can be "tagged" with more than 20 unique markers. This paper discusses how the tagging agents are incorporated to become a permanent component of the pellet. The results of laboratory testing are provided, verifying that the taggant does not materially affect the performance of the proppant In addition, the authors review two applications in which this new product was placed in multizone frac-pack completions in several deepwater GOM completions. The paper also describes basic laboratory techniques used to successfully identify the source of prop-pant found in a surface choke subsequent to the frac. The potential economic savings provided by this novel approach are presented, as well as other potential applications for this new product.

Permanent Reservoir Monitoring in Subsea Wells Attains New Level

Technology Update Some material in this article has been previously published in papers SPE 116474 and 116476, presented at the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The figures for this article originally were published in paper SPE 116474. Despite the credit crunch, worldwide subsea activity is still forecast to grow rapidly. In its recent 2009 subsea forecast, Infield Systems indicated that subsea drilling and completion expenditure will more than double to USD 80.5 billion between 2009 and 2013, from a total of USD 31.9 billion during the period from 2003 to 2007 (Infield 2009). Coupled with the increase in expenditure, Infield forecasts 3,222 subsea wells to be installed from 2009 through 2013, vs. 1,958 wells installed between 2004 and 2008. A large percentage of these wells will require sand control. In market-share terms, Infield forecasts that Africa will remain the largest sector, representing 29% of the forecast capital expenditures between 2009 and 2013, followed by North America (25%), Latin America (19%), and Europe (13%). The remaining spending will be spread between Australasia, Asia, and the Middle East and Caspian region. Despite this growth in the number of subsea wells, the expense of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity, drainage, and flow assurance. This has led to an industry need for real-time data from sensors located on the sandface. For those wells requiring sand control, an additional constraint is that sandface sensors must be deployed on a separate completion run. Reservoir-Monitoring Challenges in Dual-Stage Completions Most wells with sand control use completion components that are deployed in multiple stages. This presents a challenge to achieving measurements from monitoring equipment located in the lowest stage of the completion because sensor power and data are required to be transferred across the junction between the lower and upper completion stages. Consequently, reservoir monitoring in dual-stage completions has generally been limited to measurements of pressure and temperature near the production packer in the upper completion. These types of sensors cannot distinguish the downhole conditions of individual zones. Placing the sensors at the sandface, where the fluid enters, would take permanent monitoring to the next level because it enables operators to better understand the flow from each producing zone. This has now been achieved by an operator in southeast Asia who has deployed the Schlumberger WellWatcher Flux digital-sensor array system onto the screens of six openhole gravel packs in a subsea gas field. Data from those sensors has been transmitted to shore during cleanup, with the output used to make interpretations of permeability and cleanup efficiency for each producing zone.

Esso Australia's process safety management process

Safety is a core value at Esso Australia. We strive to observe the highest standards of safety to ensure that nobody gets hurt in our operations. We believe this goal can be achieved through a broadly shared commitment to personal and process safety—both of which are managed using our operations integrity management system (OIMS). In the Gippsland region of Victoria, Esso Australia operates oil and gas production facilities ranging from sub-sea completions to substantial staffed offshore facilities, an onshore crude stabilisation, three gas processing plants and a natural gas liquids fractionation plant, all interconnected by a network of offshore and onshore pipelines. Every day Esso’s Gippsland operations produce millions of litres of crude oil and millions of cubic meters of natural gas. Having all this fuel energy flowing through these plants each day at high pressures, and widely ranging temperatures, it is imperative that it is safely controlled and contained by the process equipment. How do we do this? With process safety systems. Process safety is a crucial component of OIMS that ensures Esso’s assets are operated and maintained in keeping with corporate and industry safety standards. In this presentation we show how process safety is managed within OIMS and how the people within Esso individually and collectively contribute to it. Our work in this area has recently been captured in a training package that includes a DVD shown at the conference. It was created to raise the awareness and understanding of all Esso employees about the principles that underpin Esso’s approach to process safety. This abstract outlines how we approach process safety across the life-cycle of our facilities and the role people play in managing this very important aspect of our work. Our training reinforces the message that responsibility for effective management of process safety lies with every employee and how OIMS is designed to assist people to achieve the desired results where all risks are appropriately managed. We have sought to connect the concepts used to manage personal safety, which are well understood by the workforce, with those that are needed to understand how to manage process safety.

Technology Focus: Field Development Projects (November 2008)

Technology Focus We all are aware of, and have been affected by, the large swing in oil prices over the past 4 years. I have asserted the importance of evaluation and management of uncertainties when planning the development of a new field or even when revisiting options for mature fields. Higher oil prices may reduce financial risks temporarily for a certain project; however, the complex decisions involved in field development, as well as the many variables to be dealt with, will make almost every project extremely risky. Ultimately, decisions taken in earlier stages, when uncertainties abound, are among the main factors that will determine the level of success of a project. Higher prices may improve the results, eventually, of a project that otherwise would be considered a failure, but the fact is, among the various uncertainties in our business, oil price is paramount. With that in mind, we should give utmost attention in management of uncertainties existing in other factors related to field development, ranging from well drilling to reservoir characteristics. Many in our industry agree, which can be seen by new approaches and recent development of various creative and exciting risk-management tools. Our featured papers this month have some wonderful examples. On a personal note, I would like to mention that after 5 years of writing this column, initially for Subsea Completion and later for Field Development, in October 2008, I will replace Ed May as Chairperson of the JPT Editorial Committee. Ed did a fantastic job of chairing over the last 4 years, and I will do my best to follow his steps, maintaining JPT's status as the primary publication in our industry. I must thank all of you for your constant encouragement and so many thought-provoking emails. Please feel free to continuing writing to me. Thank you. Field Development Projects additional reading available at the SPE eLibrary: www.spe.org SPE 108891 • "Using Geomechanics To Optimize Field-Development Strategy of Deep Gas Reservoir in Saudi Arabia" by Mahbub S. Ahmed, SPE, Saudi Aramco, et al. See JPT April 2008, page 78. SPE 113831 • "The Benefits of Integrated Asset Modeling: Lesson Learned From Field Cases" by M. Rotondi, Eni, et al. SPE 113554 • "Selecting an Optimal Field-Development Strategy for the Vankor Oil Field Using an Integrated-Asset-Modeling Approach" by D.A. Antonenko, OJSC Rosneft Oil Company, et al. Additional reading available at OnePetro: www.onepetro.org OTC 19254 • "An Overview of the Roncador Field Development, a Case in Petrobras Deepwater Production" by E. Bordieri, Petrobras, et al.