BP Deploys Drilling Automation Package on Alaska's North Slope To

® Originally appeared in World Oil JUNE 2019 issue, pg 47-53. Posted with permission.

DRILLING TECHNOLOGY BP deploys drilling automation package on Alaska’s North Slope to decrease connection times, improve safety and efficiency

In a landmark project, BP the business of drilling a well has begun the industry, redefining well construction brought together process to shift. and driving a push beyond “knowledge automation, wired drill pipe, hoarding” to advanced, product-focused THE NECESSITY OF AN UNBIASED drilling apps, and downhole integrated technology ecosystems. TECHNOLOGY INTEGRATOR National Oilwell Varco (NOV) has drilling dynamics tools to Two things have become increasingly acted as a first-mover technology integra- prove the viability of closed- clear as the industry has shifted and grown tor in drilling automation while recogniz- loop drilling automation in over the past decade. First, it has become ing the need to surmount the industry’s an extremely technically clear that no single company has acted as hesitance to implement fully automated challenging environment. a true technology integrator—a company systems. This article explores NOV’s that will take risks, capital or otherwise, drilling automation initiative and a re- to redefine a business that has typically cent project, which has seen the broad- ŝŝANDREW COIT, STEPHEN FORRESTER evolved very slowly, conservatively, and est and most successful implementation traditionally—but that such a role is a of the automation package to date, with and STEVE PINK, NOV; CARLOS critical necessity to help facilitate indus- BP Alaska and Parker Drilling. It is a SCHIAVENATO, BP; DANIEL BLYDENBURGH, try-level progress. Second, companies multi-business story, with nine groups Parker Drilling that establish a new type of paradigm for from within NOV—covering everything industry growth must be able to overcome from rig equipment to wellbore technolo- historical perception and clearly position gies—unified via a strategic services de- Drilling automation is arguably the oil themselves as adopters of new technology. livery team to ensure the results achieved and gas industry’s most talked-about sub- To move beyond the typical limiters of justified the operator’s investment in au- ject, with a multitude of papers and arti- drilling automation, the industry must buy tomated drilling. cles written to discuss the topic and com- into the idea that this is not just a solution mittees formed to explore its relevance to be implemented on a project-by-project THE AUTOMATION VALUE and potential. Much has been said of the basis. In short, drilling automation has no PROPOSITION: TECHNOLOGY IN value of linking surface rig equipment beginning, middle, or end; it is an actual SCOPE with downhole sensors and real-time pre- way of optimally conducting business in NOV began developing a closed-loop dictive models to enable optimized drill- 21st century oil and gas markets. The oil drilling automation system several years ing, and that value will be taken a step and gas industry is generally slower to ago to address the challenges of well con- further as more and more aspects of well adopt new technologies than other indus- struction in an industry that was increas- construction are automated. tries, and many of the technologies the in- ingly adopting technology to accomplish The path to this point has not been dustry does ultimately adopt are still not its goals. This early version of the drilling without struggle, as financial, operation- as advanced as those of other industries. automation system continued to mature al, and cultural issues have challenged Understanding and accepting this truth is as incorporated technologies were refined, drilling automation’s ability to deliver the first step to moving forward and accel- new products were integrated, and proj- the results necessary to justify the invest- erating growth in meaningful ways. ect implementation revealed strengths ment. Companies across the board, from Working within the bounds of the and weaknesses. The culmination of this operators and drilling contractors to ser- standard technology life cycle and un- cycle of improvement was a closed-loop vice and manufacturing companies, have derstanding how the products and tech- system that uses sensor output to control worked to develop some form of drilling nologies will move beyond the research both the rig machinery and the processes automation, but uptake has remained and development phase and into maturity performed via that machinery, creating an slow over the past several years due to (and commercial viability) will also help effective feedback loop where high-speed budget cuts, substantiated by the indus- companies on all fronts to maximize the downhole data drives the decision-making try’s risk aversion to such a sweeping, return on investment when implement- and automation of the surface equipment. non-traditionally linear, integrative tech- ing automation. This will occur simul- Closed-loop control of the machines ul- nology change. As the industry has slow- taneously as the implemented systems timately enables drilling optimization, a ly emerged from the downturn, however, provide the greatest possible benefit to sought-after value driver for operators.

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The full drilling automation system the automation system by sending more ing safety. This justifies requiring the op- (Fig. 1) incorporates a host of intel- precise measurements on borehole condi- erator to take a more balanced planning ligent applications that are designed to tions, which enables downhole phenome- approach when assessing how drilling au- improve drilling performance. These ap- na identification and drillstring dynamics tomation can assist them in accomplish- plications reside in NOV’s drilling pro- management. ing their business goals. cess automation platform, which is de- To better understand the potential Speed—with the main objective be- ployed in an NOV control system. The of closed-loop drilling automation, one ing to reduce the time it takes to complete applications use various methods of data needs to better understand the financial standard drilling activities—is measured collection and algorithmic analysis to due diligence that goes into drilling a well. across performance categories, from con- identify and address performance limit- Speed has been a main driver, as it has a nection times to ROP, and is prioritized, ers, accomplishing everything from con- clear impact on day-to-day financials in due to the impact of speed on critical finan- trolling downhole weight on bit (WOB) relation to how quickly the well is drilled. cial drivers like CAPEX, OPEX, and AFE. and mitigating stick-slip to identifying Drilling consistency and HSEQ manage- With speed as a main driver, the secondary equivalent fluid density (EFD) in real ment, which have less upfront financial concern becomes consistency. If increased time—in multiple drillstring locations— impact but provide greater long-term performance can be achieved, how does or optimizing mechanical-specific energy benefits for drilling programs and opera- the operator ensure that results are repeat- (MSE) parameters. tions, have typically followed. able—can the technology, that is, be relied Data are collected with a downhole- Speed has been the most immediately on to obtain similar results throughout the drilling-dynamics sub and sent to the visible component of the value proposi- operation in a predictable fashion? HSEQ surface in real time via wired drill pipe, al- tion, often creating the false perception management completes the value propo- lowing the software applications to then that speed is the most important value sition, with the understanding that im- interpret and analyze the data and distrib- driver. However, pilot deployments have proved HSEQ management is effectively ute demands accordingly to the rig’s con- demonstrated the other two components improved decision-making. trol system to adjust the functions of the of the value proposition—drilling consis- This could be interpreted literally— equipment. Along-string measurement tency and HSEQ management—actually with automated drilling processes tak- (ASM) tools round out the capabilities of enable faster operation without sacrific- ing personnel out of harm’s way in many

Fig. 1. The full closed-loop drilling automation system, as used by NOV on this project. Real-time operations support center

Tool communications • Satellite communications to remote viewing and control

Wired Agitator™ tool Top drive Downhole data

• Network connectivity • WOB Downhole data Bidirectional high-speed communication during drilling and tripping • Torque • DAQ internal BOP • Three-axis vibrations • Enhanced top drive control • Internal pressure • Annular pressure Wired drill collars/ • Azimuth HWDP • Inclination • Gamma ray

BHA DAQ sub Automation-enabled control system Visualization Interface sub from third-party service company

Wired drill pipe Wired MWD

Optional wired drill collars/HWDP

Mud motor or RSS Drilling applications Machine control • ROP optimization • Top drive Drillstring DAQ sub/ • Risk mitigation • Drawworks network booster sub • Performance steering • Pumps (option to be • Procedural adherence to instrumented or not) operational best practices Bit DAQ sub

48 JUNE 2019 / WorldOil.com DRILLING TECHNOLOGY instances—or with regard to identifying in this environment has presented compa- essary to do business there. and mitigating harmful drilling dysfunc- nies with significant environmental and In addition, the high cost of further tions and downhole phenomena that im- operational hurdles, including sub-zero development makes any prospect a risky pact both safety and performance. Note temperatures, heavy winds, advancing endeavor, due to nonexistence of typical that in this model, HSEQ management sea ice, flora and fauna sensitivity, fragile infrastructure. In their role as a technol- being the final component in the hierar- geological conditions, and stringent local ogy pioneer and innovator—and to de- chy does not imply any lack of commit- regulations. Despite these challenges, BP termine an economically sound option ment to proper HSE practices by an op- erator, but rather a mindset toward the Fig. 2. Parker Drilling Rig 272, one of the company’s Arctic Alaska Drilling Unit (AADU) rigs potential impact of drilling automation. operating on the North Slope. To further this point, the bottom-line val- ue proposition to the industry is a com- plete inversion of the time immediacy of each benefit within the three-pronged val- ue proposition. When ordered according to organizational value, the order of the automation value proposition is HSEQ management, consistency, and speed. With this project, BP was one of the first operators to rise above the drilling-speed- focused automation business model of the downturn, with HSEQ supplanting speed as the primary value driver. By taking the focus away from purely speed-based drill- ing improvements, the benefits of consis- tency and better decision-making were made clear. This essentially allowed BP to improve evaluation capabilities in both well planning and execution by seamlessly integrating lessons learned into every auto- has spent more than 50 years in Alaska, that would enable more efficient and safer mated well program. Measurable benefits beginning with its first project in 1959. drilling as well as leverage the benefits of included: mitigation of downhole events, In 1968, the company began to drill at digitalized drilling—BP partnered with increased downhole and surface equip- the massive Prudhoe Bay oil field, which Parker Drilling, NOV, and a third-party ment service life, simplifying and continu- remains one of the most prolific fields in service company to deploy drilling auto- ously improving processes, strengthening the United States. Beyond this accomplish- mation for a multi-well pilot project. competencies, managing costs, and main- ment, Prudhoe Bay has also often served as In this landmark drilling project, NOV taining open and honest reporting. a proving ground of sorts for new and in- installed its drilling process automation Beyond the obvious advantage of BP novative drilling techniques and technolo- platform along with drilling performance being an IOC—and having the time gies and is one of few onshore drilling areas applications on Parker Rig 272 (Fig. 2), an flexibility and capital allocation associ- regarded as relevant for drilling technology Arctic-designed modular drilling unit con- ated with that designator—the company validation before taking them to offshore trolled by an integrated rig control system. also benefitted from having a culture that applications. Everything from multi-lat- The platform was then combined with embraced innovation and recognized the eral drilling and enhanced oil recovery to downhole tools and sensors using wired comprehensive impact of the new tech- coiled tubing and drilling automation has drill pipe telemetry. KPIs were set for the nology to drive a step change if properly been deployed and, in some cases, pio- automation pilot to determine the success implemented. The role of Parker Drilling neered in the field and integrated into BP or failure of the systems, with the initial as a partner and technology enabler was and other major companies’ operations. project objectives including the following: also foundational to the success achieved, As time passed, it became clearer that 1. Evaluate the readiness of the drill- as drilling contractors in the oil and gas in- improved efficiencies and technologies, as ing process automation platform for dustry are the physical end-users of drill- well as sound fiscal policy, would be neces- wider deployment across BP ing automation technology as value con- sary to maintain the competitive status of 2. Evaluate the reliability of the wired tributors to their customers’ bottom lines. Alaska’s oil and gas industry without com- drill pipe connection promising safety. What has been called the 3. Evaluate the maturity of the drilling CASE HISTORY “easy oil” is largely gone, and the resource- performance applications running rich North Slope has become increasingly within the automation platform Background. The Alaskan North Slope challenging and costly to drill. The remote 4. Evaluate the impact of the technol- hydrocarbon drilling area is a region lo- location and extreme climate of the region ogy suite in reducing well costs on cated on the northern slope of the Brooks contribute to the difficulty of both drilling the Alaskan North Slope. Range along the coasts of the Chukchi Sea and transporting resources, driving up the The wells that were drilled during the and Beaufort Sea. Drilling for oil and gas already-significant capital investment nec- pilot were two-section sidetrack wells that

World Oil® / JUNE 2019 49 DRILLING TECHNOLOGY served as production replacement wells. (i.e., torqueing and untorqueing uses automated vibration dampen- A phased approach was decided upon for connections), tripping, and BHA ing to mitigate torsional vibration the project, which began by proving the makeup and breakdown. In addi- and reduce stick-slip oscillations automation platform’s system and appli- tion, the platform structures data and during drilling operations. cation functionality on the first well. On defines activities, which in this case 6. An enhanced measurement system the second well, the automation platform enabled BP’s engineers to develop (EMS) tool, placed on the bottom was used to optimize drilling parameters lessons learned and potentially scale of the wired drillstring, that acquires with surface data using performance drill- best practices across other regions/ high-frequency downhole data on ing applications. Wired drill pipe with rig fleets. WOB, torque on bit, bending, rota- high-speed downhole sensors was added 2. Wired drill pipe, which incorporates tion, three-axis vibration, annular on the third well, and on the fourth, wired a coaxial cable along the length of the pressure, internal pressure, and tem- drill pipe was integrated with the rotary drillstring from the rig sensors near perature. steerable system. the drill bit, and the wired pipe’s asso- 7. A collar-based ASM tool that pro- A wired underreamer was added on ciated high-speed telemetry network, vides streaming visualization of the fifth well, and by the sixth well no ad- which uses inductive coils located in downhole data when connected to ditional technology was specified. The the drillstring connections to enable the wired drillstring, acquiring data goal then became moving into greater bidirectional data transmission be- on three-axis vibration, tempera- degrees of automation and iterative appli- tween surface and downhole tools at ture, annular and bore pressure, and cation usage while achieving consistency up to 57,000 bits per second. rotational velocity in real time. and repeatability. A challenge for all wells 3. An autonomous, two-parameter au- 8. A real-time visualization application was balancing ROP to remain within todriller that uses surface WOB and that tells the story of the annulus— pressure and wellbore stability bound- rotary RPM to minimize surface the four-dimensional health of the aries. Ownership by both the BP Alaska MSE and maximize ROP. Advanced wellbore—by displaying surface pa- Drilling Team and Parker Drilling was key capabilities on this project added the rameters, equivalent circulating den- to the success of the project, as was ongo- ability to use high-speed downhole sity (ECD) in a heat map, interpolat- ing technical support from the BP Central vibration and MSE to optimize ed ECD at the shoe, and vibrations. team in Houston, Texas. surface parameter selection. Incor- porating the downhole portion of RESULTS Equipment/technologies. The follow- the technology also allows the user BP achieved time reductions using ing integrated suite of NOV automation to weigh the relative importance the drilling process automation platform, technologies was used on this project: of the determined parameters—in performance drilling applications, and 1. A drilling process automation plat- this case, ROP versus MSE versus wired drill pipe. Using the platform, BP form that sits on top of the rig’s base- downhole vibration management. saved approximately 4 min. per interme- level control system. The platform 4. An autonomous, real-time diate hole-section connection and 2 min. uses an imported well plan that de- downhole autodriller application per production hole-section connection, scribes desired drilling parameter that automatically accelerates and when compared with relevant offsets. ranges, performing the planned op- decelerates the drawworks by ad- Weight-to-slip sequences showed compa- erations until total depth is reached. justing surface WOB to maintain a rable results between the driller and the On this project, exceptions to this desired downhole WOB, specified platform in delivering the sequence, but (i.e., non-automated processes) in- by the driller. much less interaction with the drilling cluded pipe handling while in slips, 5. A stick-slip prevention software that control system was necessary. This meant that the driller could focus more on ana- Fig. 3. Substantial time savings achieved when using the drilling process automation lytically supervising and managing the platform more than 90% of the time during drilling connections (based on one-second overall drilling operation versus manually data). Total drilling connection time (weight-to-weight) was reduced by an average of 30% versus non-automated connections on the project. performing each sequence. Slip-to-weight sequence performance Average slips-to-drill time based on Standard deviation, slips-to-drill time platform utilization based on platform utilization showed that the platform was faster than 12 3.50 the driller’s manually controlled functions 11 in executing the sequence, which led to 10 3.00 9 several hours of time-savings throughout 2.50 8 the program, Fig. 3. Additionally, the sys- 7 2.00 tem was significantly more consistent than 6 the driller’s manually controlled functions 5 1.50 9.55 10.33 6.07 3.07 3.28 1.58 4 during each step of the process. As varia- 3 1.00 tions in human performance were a given, Average slips-to-drill time, min. time, slips-to-drill Average 2 0.50 consistency was desirable due to the po- 1 0 min. time, slips-to-drill deviation, Standard 0.00 tential of the system to manage operation- Usage ≤ 50% Usage between Usage > 90% Usage ≤ 50% Usage between Usage > 90% al events (such as starting the pumps) and 50% and 90% 50% and 90% Platform usage post connection Platform usage post connection potentially prevent a major NPT event in unstable openhole scenarios.

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The platform achieved a connection- tions that were integrated in the process impact of a stuck-pipe event. The EFD time, standard-deviation reduction from automation platform and wired drill pipe viewer allowed much faster root-cause 8 min. to 2 min. or less, with time reduc- network functioned in harmony to tailor analysis than if only traditional telemetry tions exceeding 75% in some cases. Vi- the operation of two key surface ma- speeds were available and had far greater bration management during slips-to-drill chines to the drilling application while visibility than what was provided by only and drill-to-slips sequences were also on bottom: the top drive and drawworks. a single MWD placement. Unique to this kept at low levels by the platform, helping The stick-slip prevention application, application, wellbore breathing was a to prevent premature bit/tool wear and which was run almost always when in high-risk phenomenon that was tradi- extending run length. rotary drilling mode, was able to con- tionally time-consuming to diagnose Wired drill pipe saved time in both sistently prevent the torsional vibration and characterize with typical pre-auto- surveys and downlinks, with the most fundamental frequency from manifest- mation technology packages. The EFD substantial result being the effective ing and becoming an excitation source viewer’s capability to illustrate a multi- elimination of all flat time and invisible for the drillstring. The dual-parameter node, four-dimensional “story of the lost time related to downlinking. The and DWOB autodrillers (Fig. 4) were annulus” allowed rig crews and drilling addition of wired drill pipe telemetry able to consistently reduce MSE versus engineering teams to much more quick- eliminated the need to use mud-pulse te- offsets, and in formations that were not ly—and much more reliably—identify lemetry to send downlinks to the BHA, performance-limited by ECD or forma- and mitigate wellbore breathing events. allowing 5.5 min. to be saved per off- tion concerns, ROP increases of 10 to The EFD viewer (Fig. 5) also proved bottom downlink. This measurement 50% were consistently seen. valuable in helping to optimize tripping includes the time taken to pick up, send The EFD viewer also proved to be an speeds by allowing the calibration of the the downlink, and run back to bottom. invaluable tool to assess hole cleaning in customer’s tripping speed models in real The real-time downlink, made possible real time and help mitigate the negative time, leading to substantial time savings by the high speed of the telemetry net- work, also provided uninterrupted data Fig. 4. Using the dual-parameter autodriller, when in select formations that were not to surface during downlinking, while performance-limited by ECD or formation concerns, enabled MSE reductions of 42.1%, mud-pulse downlinking creates a pe- ROP increases of 10.5%, and a reduction in CPF of 9.5%. Hole size for the formations was 8½ × 9⅞ in. These improvements represent averages based on conservative use of the riod without receiving data from the application. downhole tools. ROP with system on/o Cost per foot with system on/o Achieving desired toolface in real time 80 180 was made possible by high-speed telem- etry transmission when drilling with a 70 mud motor and setting whipstocks for 60 160 sidetracked wells, which was a significant benefit to both the directional drillers and 50 the operations teams. Surveying was also 72 79.6 improved by using the wired drill pipe. 40 140 ROP, ft/hr ROP, The northern location of the project, 30 combined with complex well trajecto- ries and well proximity in a mature field, 20 120 meant that multiple surveys were often 10 required, adding 10 min. or more of wait 0 time per stand. 100 O On With wired drill pipe, the process Status system was effectively identical, but the surveys MSE with system on/o were available much faster—approxi- 80 173.5 157 mately 20 sec after the pumps were at 600 Calculated cost per foot, ISD per foot, cost Calculated tool-operating flowrates. These activi- 550 ties, when done via the drilling process 500 60 automation platform, were completed 450 in 2.5 to 3 min. less per survey versus 400 surveys done with mud-pulse telemetry. 350 40 The wired drill pipe telemetry achieved 300 555.4 network uptime—measured as the per- 250 200 centage of wired drill pipe uptime versus 321.7 the amount of time the wired pipe was MSE surface calculated Average 150 20 connected to surface—of more than 100 99%, exceeding BP’s expectations across 50 more than 48,000 ft and 800 hr of on- 0 0 O On O On and off-bottom drilling time. Status system Status system The drilling performance applica-

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Saudi Arabia. He graduated with a BS degree in Fig. 5. The EFD viewer showed a significant increase in ECD due to cuttings loading in mechanical engineering from Southern the annulus, which was further exacerbated by cuttings fall-out during a connection. Methodist University in Dallas, Texas. The data also clearly show significant pressure spikes associated with the breaking of the gel structure of the drilling fluid. Visibility of this high-speed data in real time helped STEPHEN FORRESTER is a the operator to ensure effective hole cleaning at specific measured depths, which also Marketing/Technical lowered the risk for possible stuck-pipe events. Communications writer at NOV, where he oversees strategic marketing communications and technical writing at the corporate level. He joined NOV in 2014, in the Dynamic Drilling Solutions business unit, where he primarily wrote about drilling optimization and downhole drilling dynamics. Prior to NOV, Mr. Forrester worked for the oil and gas division of Lloyd’s Register, where he was a technical editor for reports on inspections and certifications of subsea BOPs.

STEPHEN PINK is the Sales Director for NOV’s eVolve optimization and automation in North and Latin America, where he manages sales and technical services across the regions. He has more than 20 years of experience in the oil and gas industry, including as a mudlogging geologist with Baker Hughes, MWD field engineer with Halliburton and Sperry Sun Drilling Services, and multiple positions for NOV. Mr. Pink’s in areas where tripping speed models inspiring the team to achieve results and broad range of experience includes reservoir were conservative. embrace the new technology. evaluation, petrophysics, downhole drilling All results were underpinned by pro- dynamics, surveying, and directional drilling. He served in the British Royal Navy and later cedural adherence through automation. CONCLUSION graduated with a BSc degree in geology. Once the automation system was imple- Driving a paradigm shift in drilling mented, not only could historical prece- automation demands that a transition oc- CARLOS SCHIAVENATO is the dents and standard operating procedures cur and that technology integrators take a Rig Intake Superintendent for BP Alaska, as part of the be guaranteed, but new lessons only had more consultative business approach. This Global Wells Organization, to be learned once before they could be transition must occur simultaneously with where he oversees programs systematically implemented. This high- increases in adoption rates for automation that ensure rigs are up to industry and BP standards. lights the benefit of a system driving con- technology, improvements in infrastruc- He has almost 25 years of experience in sistent procedural adherence rather than tural support driven by growing regional drilling engineering, operations, and project relying on variable human performance. implementation, and demonstrations of management, working in Houston, Azerbaijan, and Colombia as a drilling engineer, program In addition, all parties took forward les- successful projects that prove value and manager, company man, team leader, and sons learned for future project work. Be- continually lower the cultural adoption wells superintendent for BP. Mr. Schiavenato yond KPIs, there were several critical ele- hurdle. In addition, companies must grad- also has previous experience working for Schlumberger’s integrated project ments that made the project a success. uate from a project mentality and approach management team in Mexico, as part of First, there was a phased technology drilling automation as an easily imple- an offshore exploration campaign. He is a graduated petroleum engineer with a approach, starting with implementation mentable way of doing business. Moving degree from La Universidad de América in of the drilling process automation plat- forward, adopters in this space must ask Bogotá, Colombia. form and moving through drilling appli- the question: how will they weight their cations, wired drill pipe on the motors, value proposition between performance, DANIEL BLYDENBURGH is the Operations Manager for and wired drill pipe on the RSS. Doing consistency, and HSEQ management? Parker Drilling’s Alaska this helped ensure that the crew was not business unit, where he leads overburdened by having to use so many all operations for the ANDREW COIT is in Global company in the region. He new processes and systems from the proj- Project Management for NOV’s joined Parker Drilling in 2011 eVolve Drilling Optimization and during construction of the company’s Arctic ect’s outset. Secondly, front-end simula- Automation Services group, tor training on each technology element Alaska Drilling Unit (AADU) rigs, starting as a principally focused on building driller and subsequently becoming a rig helped familiarize the crew with these NOV’s drilling automation manager and area superintendent. Through components before actual field use as part business in the Middle East. his more than 20-year tenure in the Alaskan Most of his 10 years in the drilling industry have drilling industry, Mr. Blydenburgh also worked of the phased deployment. Third, NOV been spent with NOV in various roles, in field in various field positions, where he gained helped frame the expectation that BP, and engineering, new product development, drilling extensive experience in operations support. more specifically the drilling engineering optimization, technical sales, project He is a lifelong Alaskan and carries a passion management, and business development. Mr. for his community and its people. team, would be the owners and drivers Coit has worked in the continental U.S., Alaska, of the project’s success, responsible for Canada, the UK, Norway, Oman, the UAE and

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