12 Wednesday, October 23, 2013 DAY TWO Louisiana Gulf Coast Oil Exposition 2013 Show Daily NewSpaper Louisiana Gulf Coast Oil Exposition 2013 Show Daily NewSpaper DAY TWO Wednesday, October 23, 2013 13

Rentals. He partnered with private equi-ty firm Clairvest to take his company to the next level. “We were a small regional company, and now we are a big national company,” he said. Clairvest came in and offered expertise in financial reporting and “professionalized” the business.

“We brought in a stronger executive management team and stronger branch management. We upgraded technology and all aspects of business,” said Hogan. “Clairvest stays in the background and lets us operate. We don’t always agree on

the best way to do it, but we always have productive discussions. All private eq-uity groups are different. Look at where you are, and what you want to do.”

“You need a partner who understands what the cycle will be like,” said Michael Castellarin, Clairvest’s managing director. “One of the benefits of having a partner with experience is understanding the cy-clical nature of this sector.”

Scott Dingman, an entrepreneur and the CEO of Delta Subsea, was another panelist. Dingman observed that once he

made the decision to seek private equity investment, he interviewed 85 companies before he found the right match (which was with SSL Energy Fund). “You have to be aligned with your equity partner,” he said. “They have to support you.”

John Griggs, who represented SSL En-ergy Fund on the panel, mirrored Ding-man’s remarks. “We like to build business-es, starting small and hands-on,” he said. “We’ve started seven different oilfield ser-vices companies. We have a fund of $300 million, and we try to diversify within the

energy sector.” That diversification goal means targeting companies onshore and offshore in a variety of different plays, in an attempt to avoid excessive exposure to any one niche of the overall market.

The discussion then wound its way back to Castellarin, who saw fit to go into a bit more detail about Clairvest’s invest-ment strategy. “We aim to put up 25% of all money in a deal,” he said. We try to walk the talk. Our preference is to do minority deals, where we own less than 50%. That is a critical part of achieving alignment.”

Castellarin went on to say that there is no substitute for communication be-tween the equity firm and the company that they have invested in. In one exam-ple, Castellarin noted that he still holds a weekly call, more than six years into the deal with one company. He also is a firm believer in well-defined financial and op-erational measurements. He says it is far easier to have data and fact-based con-versations around returns and growth. “Guessing will lead to disagreements,” he said. “Improving reporting is critical to avoiding disagreements.”

The free-flowing panel discussion wrapped up with an analysis of exit strategy. “We don’t go into investments without an exit strategy,” said Michael LeBourgeois, a partner at NGP Energy Technology Partners. “We map it out, in conjunction with where the management team is, and where they see the exit going. If you go into one of these deals, where you are misaligned with the other side from Day 1, you are likely to have dis-agreements.” LeBourgeois reminded the audience that all private equity groups are different. “We all have our strengths and weaknesses,” he said. •

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Collaborative planning pays off for Norwegian operator’s first subsea completionMARTIN OLIPHANT, Weatherford

Subsea completions of oil and gas wells, in which the wellhead and signifi-cant control architecture are located on the sea floor, have been used success-fully to improve the economics of off-shore well development. But, as wells are drilled and completed in deeper waters and higher-temperature/high-er-pressure (HPHT) reservoirs, new completions solutions are required for safety and optimized production.

SUBSEA COMPLETION OFFSHORE NORWAY

A new operator in the Norwegian sector of the North Sea needed a solu-tion for the subsea installation of two wells at a water depth of approximately 417 ft. The installation represented the operator’s first subsea completion in Norway, which requires compli-ance with some of the most stringent offshore regulations in the world. Norway’s Petroleum Safety Authority (PSA), which oversees technical and operational safety in Norway’s oil and gas operations, places special priority on partners working to reduce accident risks. The PSA also mandates that ap-propriate safety barriers are imple-mented consistently and maintained over the life of the installation.

Weatherford was chosen to design, build and install the subsea completion for two satellite oil wells with 9⅝-in. mainbore casing, which would be tied back to a nearby wellhead platform. The wells would contain connection points for a production pipeline and con-trol cable with pipes for hydraulic and chemical delivery, signal cables, electri-cal power cables and gas lift.

DEVELOPING OPTIMAL COMPLETION

Weatherford’s Optimum cased-hole completion system was selected for this application. The system is de-signed to implement various mix-and-match completion technologies as a customized solution for the needs of a given well.

With a thorough review of the reser-voir conditions, expected production profiles, and planned operating life of the wells, Weatherford’s completions engineers conducted upfront engi-neering, project planning and prod-uct development work. This included comprehensive testing of candidate components under expected downhole conditions of temperature, pressure, load and strain.

Based on this early review and quali-fication testing, Weatherford and op-erator staff finalized a fully integrated, subsea completion system for both wells. The main components of the lower completion consisted of:

•  More than 100 5½-in., 20-lb metal-mesh standalone screens, with an inflow control device, to regulate flow and prevent formation sand

from creating localized erosion—commonly known as a “hot spot”—on the screen

•  Swellable  packers  to  isolate  differ-ent producing zones of the forma-tion and prevent cross-flow in the event of a pressure differential

•  Liner  packer  hangers  to  take  the weight of the tubing string and act as barriers between the reservoir and casing.

The upper completion comprised:•  A 9⅝  5½-in. OptiPkr hydrostat-

ic set, removable production packer to provide a seal between the out-side of the production tubing and the inside of the casing

•  A chemical injection mandrel with shear-out valve to deliver chemi-cals, such as scale and paraffin in-hibitors, during production and prevent the need for a later inter-ventional installation;

•  Two  5½-in.  gas-lift  mandrels,  the lower with an orifice valve and the upper with an unloading valve, as simulations indicated the wells would need artificial lift to main-tain production rates within 12 to 18 months

•  An  Optimax  tubing  retrievable, subsurface safety valve (SSV) to provide positive shutoff protection in the event of a catastrophic loss of well control. Per PSA, all wells operating in the Norwegian North Sea must have an SSV in place to contain well-control events and prevent the release of reservoir flu-ids to the environment

Next, Weatherford developed a quality-control plan with the operator, which documented quality-assurance requirements for the manufacture, in-spection and testing of all cased-hole completions equipment for the wells. It also detailed every sequence of activi-ties from manufacturing to the delivery of equipment, with detailed descrip-tions of activities, parties responsible for approvals, reference documents and acceptance criteria. The document also captured any operator quality-assur-ance and control requirements.

INSTALLATION PROCESSPrior to running any equipment

downhole, all parties responsible for system deployment met to systemati-cally review the steps required for safety and efficiency. This process, known as a “well on paper,” was repeated several times over five days to give the engi-neers a thorough understanding of each step, and to address potential installa-tion setbacks.

The installation plan for both wells began with a pre-job safety meeting with all personnel. A BOP was installed and tested to 250 bar with brine at a spe-cific gravity (s.g.) of 1.03.

The lower completion, consisting of  102  joints  of  5½-in.  screens  with swellable packers spaced between, was installed. The 9⅝-in. mainbore casing

was prepared for the upper completion by scraping and pressure testing to 250 bar with a 1.45 s.g. fluid.

The procedure for the upper comple-tion consisted of running in hole:

•  The  5½-in.  tubing  handling  equip-ment, spooling units and accessories.

•  A 7-in. seal stem with indexing mule shoe  and  a  7-in.  to  5½-in.  cross-over assembly to a measured depth (MD) of 3,090 m.

•  One  5½-in.  tubing  joint,  followed by a bottom-landing nipple.

•  OptiPkr production packer, includ-ing a top-landing nipple, followed by 5½-in. tubing joint.

•  A  downhole  pressure-test  gauge mandrel and chemical-injection mandrel. Separate pressure tests were conducted on the pressure-test gauge (517 bar for 10 min), the fitting between the mandrel’s injec-tion valve and the control line (345 bar for 10 min) and the control line (100 bar for 10 min).

•  Gas-lift mandrel  with  orifice  valve and gas-lift mandrel with an un-loading  valve  and 5½-in.,  17-lb  13 Cr tubing in between.

•  More  5½-in.,  17-lb  13  Cr  tubing according to tally, to ensure correct SSV depth placement

•  Optimax  SSV,  with  splice  subs above and below, followed by a pressure test of the SSV control line (690 bar for 10 min). The control line was pressured up and main-tained at 400 bar to keep the SSV open, while running additional tub-ing in hole.

•  Additional tubing until the tubing-hanger depth was reached, followed by a bumper wire anchor sub.

•  A 10¾-in. X 5½-in.  tubing hanger was then run in hole and landed, with additional pressure tests from above and the SSV. The production packer was set, followed by final pressure and inflow tests.

SUCCESS SPURS FURTHER COMPLETIONS

Thorough planning, collaboration, installation and testing helped ensure that both completions were installed

efficiently—two days ahead of sched-ule—with no injuries or recordable incidents. This success prompted the operator to use this strategy for future wells in the field and in the greater North Sea. •

FIGURE 1

Optimax tubing-retrievable, subsurface safety valve.

FIGURE 2

OptiPkr hydraulic-set, removable production packer.

FIGURE 3

North Sea Optimum subsea completion system.

PRIVATE EqUITY, continued from page 1

The recommended practice aims to cover risk management issues that are particular to shale gas fields. DNV is still soliciting input for the recommended practice and will continue to do so for the next couple of years. The company hopes that its new, recommended practice may serve as a reference document for inde-pendent assessment or verification.

Elements of the practice guard ar-eas as diverse as health and safety, including those specific to shale gas development; the management of en-vironmental aspects; ensuring well in-tegrity; management of water, energy and residuals; infrastructure and logis-tics; stakeholder communications; and permitting. This practice is designed to

establish trust, credibility and stake-holder confidence through indepen-dent verification. It will demonstrate that operations are conducted in a safe, sustainable manner; that best practices are in use; and that regulations are be-ing complied with.

DNV can issue a letter of confor-mance to companies that adhere to

the recommended practice. Copies of DNV’s recommended practice can be found at www.dnv.com.shale. Green is also developing a new Environmental Services team in North America, tar-geting clients in the energy sector that need environmental due diligence, eco-systems services support, and climate change positioning services. •

DNV MARITIME, continued from page 1

During the LAGCOE Day One Keynote Address, Steve Thurston, V.P. of U.S. Deepwater Development at Chevron, detailed some of the company’s latest proj-ects and future plans for the deepwater Gulf of Mexico (GOM). More specifically, Thurston focused his pre-sentation on the area’s Lower Tertiary trend, and the potential it holds for increased oil recovery and im-provements in drilling efficiency. The latest informa-tion from the company’s presence there highlighted the 3,000–4,000-bopd average flowback for the Cascade-Chinook development, which Thurston said was the Lower Tertiary’s first system to reach production.

Characterized by complex reservoirs and variable recovery factors, the Lower Tertiary presents an ex-pensive, unpredictable drilling atmosphere for any operator. At Chevron, said Thurston, the company ap-proaches the area with a so-called “deepwater factory” system, in which equipment, planning and a standard-

ized process are employed to meet operational goals. It also does not hurt that Chevron has a fleet of five sixth- and seventh-generation drillships at its disposal in the GOM, meaning the sought-after rigs can move onto exploratory drilling, leaving wells to enter devel-opment, in the meantime. The company’s upcoming exploratory campaign, said Thurston, will include the Buckskin, Moccasin and Coronado developments, which are now in appraisal.

Several of the other Chevron projects that Thur-ston mentioned in his presentation, including Jack/St. Malo, Big Foot and Tubular Bells, all received their final investment decisions in the middle of the post-Macondo drilling moratorium, during which the company gave approval to $17 billion of deepwater GOM activity. This confidence in the Gulf ’s potential is underscored by Chevron’s commitment to 31 simul-taneous, deepwater technology project partnerships,

which may help to increase oil recovery rates in the region’s Miocene and Lower Tertiary trends.

However, when asked by an audience member, Thurston said that deep water is not the sole area of focus for Chevron, with LNG, shale and conven-tionals still comprising a good part of the company’s core business. He characterized the deepwater Gulf as having “unique challenges, with large rewards,” in addition to large oil-in-place opportunities and sig-nificant flowrates.

Thurston said that “vision and commitment to de-velop technology now are essential to achieving suc-cess in the future,” which falls in line with, what he called, Chevron’s “Big Seven” for the GOM. The com-pany hopes to enhance and enable deepwater develop-ments through improved seismic imaging, increased drilling efficiency, quality completions, in-well artifi-cial lift, seafloor pumping technology, optimized. •

Chevron pursues deepwater Gulf with operational excellence, technological breakthroughsMELANIE CRUTHIRDS