OIL PRICES 

Based on the dramatic fall in active drilling rigs and now the emerging fall in weekly oil production estimates, many in the industry and on Wall Street are feeling that oil prices are at a bottom and that we have experienced the worst of the market correction. Of course, many of these optimists were among the community of believers that Saudi Arabia would orchestrate a global oil production cut to support prices last November.

 

We suspect many of the optimists were also among those most shocked by the speed of the drilling rig decline and the quick reaction by oil company managers to cut their capital spending. But now, these same optimists are heartened by the trading pattern of oil prices. In fact, one columnist pointed out recently that in the 41 trading sessions between April 1st and June 1st, WTI had risen 23 times and declined 18. The average daily increase was 30 cents, with 12 sessions posting an increase of over $1 against four posting a decline of over $1. He cited this trading pattern as confirming that the oil market has stabilized. To check that conclusion, we plotted in Exhibit 1 (see below) the daily change in WTI spot prices since January 1, 2014 to June 16, 2015. We also plotted the price of WTI. When one examines the chart, the visual picture of daily price changes on the far right looks more subdued than the period of time when WTI was falling and then bouncing off its low before retesting the low.

That increased daily price volatility is not surprising given the turmoil the industry and oil markets were in due to the unanticipated actions of Saudi Arabia and OPEC. What is interesting, however, is to examine the stability of oil prices during the first half of 2014 as reflected by the daily price change. That low volatility period was marked with oil prices rising from the high $80s to $107 a barrel, the peak price in 2014 and for this cycle. Is there sufficient evidence to proclaim oil price stability at the $60 per barrel level? We don’t know. We could make that argument, but then again we have no vested interest in making oil price calls.

BENCH MARKING OF SUBSEA, DECOMISSIONING  

EXTRACTED FROM OIL PRO

contracting and operational issues

During the first quarter of 2015, Endeavor Management conducted a benchmarking study of subsea decommissioning practices across the industry, which was funded by Petrobras. Six respected operating companies participated in this study including two majors, one large independent, one small independent, and two national oil companies. The geographic coverage spanned the world, but focused on four areas of major subsea development: North Sea, Gulf of Mexico, offshore Brazil and Australia. There was an excellent cross-section of responses to develop conclusions about industry practices and to help define a path forward for future decommissioning practices.

 

Contracting

Contracting models are one of the most important aspects of subsea decommissioning to be evaluated. Operators and contractors alike are risk averse. However, being able to quantify and subsequently commercialize risks is often the difference between a successful project and one with poor results. The majority of the respondents enjoyed a shared-risk relationship that was forged with a combination of contracting strategies to mitigate (to the extent possible) the inherent risks associated with any decommissioning project. There was no clear “best practice for contracting models” identified by the participants. Each had tried and was still using various types of contracts based on risk and the specific scope of work.

 

Key takeaways included:

  • Limiting the number of vessels by using those that can support multifunctional services, e.g. survey, diving, ROV, and clearly defining the required capabilities of each vessel such as crane capacity.

  • Contractual flexibility with the contractor(s) is paramount for a win/win.

  • Turnkey contracts work when both scope and risks can be identified.

  • Fixed day rate contracts work when there are a lot of unknowns.

  • Both contract types can be sent out for competitive bid.

  • For turnkey contracts, the scope of work must be clearly defined. Unknown risks will be difficult to quantify monetarily.

  • For fixed day rate contracts, there is less risk, but again the scope of work must be clearly defined to ensure that crew and equipment requirements are properly identified.

  • Both turnkey and fixed day rate contracts can work with the same contractor by separating the scope of work appropriately.

 

Integrated Services

The operators participating in the benchmarking study did not contract with Integrated Service Contractors (ISC). The operators either had rigs already on contract through their drilling departments or rigs were contracted for specific wells. The production groups provided vessels for decommissioning support work including ROVs, Light Well Intervestion (LWI), heavy lift vessels, and other vessels as needed. Participant’s comments suggested that ISCs are not a suitable solution except for specific turnkey activities, such as recovery of a manifold.

Cost Drivers and Time Required

The participants provided some excellent representative costs associated with the various operations. The actual costs cannot be predicted either overall or by line item due to the large number of variables associated with unknowns. Budgetary projections can be developed on a “rule of thumb” basis with contingency allowances added. Costs to plug and abandon (P&A) a single subsea well ranged from $1.1 million spent on a well in 133 m water depth using a dive vessel to over $40 million on a well in 1600 m water depth using a mobile offshore drilling unit (MODU). Most offshore projects lasted 4 to 6 weeks, but the number of wells to be decommissioned will substantially impact the time to complete the work. When planning offshore projects, it is important to include contingencies, especially for weather and potential downhole delays during P&A operations. Complexities in the number and condition of wells, size of the development, and unforeseen weather issues can greatly alter the time needed to complete the work offshore. All tools should be ready when needed and a backup plan approved in advance for any tools needed in an emergency.

 

Vessels

Larger operators tend to have vessels on contract for a variety of projects, decommissioning being one. Therefore, there is a tendency to use specialty vessels (ROV, diving, heavy lift, light well intervention, and MODU) as part of a campaign during multiple decommissioning projects. Smaller operators tend to contract vessels with multiple capabilities to reduce the number of mobilizations/demobilizations. They are also less risk averse than larger operators and tend to use LWI vessels in preparation for a MODU or to actually complete P&A work when able.The type of vessel to use for P&A varies substantially, based on operator preference and risk evaluation, the condition of the well and work to be performed, and vessels under contract to the operator in the geographic area.

 

P&A Operations

Plugging and abandonment is far and away the most expensive single task during decommissioning and is fraught with the most risks. The use of LWI vessels versus drilling rigs has many pros and cons. Large operators tend to use a full-service MODU, but they also have higher P&A costs. When employing a drilling rig for P&A work as a part of the subsea decommissioning program, it is easiest to use one already on contract and to schedule the P&A tasks as a back-to-back operation. However, drilling crews are usually not efficient with decommissioning activities because they are more focused on “making hole.”

 

Methods used for P&A include:

  • Tubing removal, though it is not universally part of the operation.

  • Cement plug installations; these are very precise as to depth and length.

  • Cutting casing; commonly at 5 m below mud line when the subsea wellhead is removed.

  • Leaving wellheads in place; this practice is becoming more popular with industry and regulators.

 

Hydrocarbon Removal

A majority of flushing operations are done with seawater for economic reasons. Obviously, there is also an environmental consideration as well by avoiding chemicals as part of the cleaning/flushing operation. Flushing of flexible components such as flowlines can be problematic due to hydrocarbons in the composite layers.

 

Cutting Casing

Mechanical cutters are by far the preferred method for cutting casing. In cases where the subsea wellhead is recovered, the depth of the main cut is fairly common at 5 m below the mudline although some wells may see smaller casing cut at much deeper depths.

 

Cementing

While “rock-to-rock cementing” is the best solution, it is generally impractical for most wells. Cementing the completion with all tubing and annulus barriers in place and verified is the most challenging aspect and steps should be followed to make this a more efficient process. There are resins available that are much better than cement for P&A, but to date resins have been used in very few P&A operations.

 

Components Disposition

Some subsea components are recovered because of potential recycle opportunities. This includes trees, pipeline end manifolds, pipeline end terminations, flying leads, and umbilical termination assemblies.In the North Sea region, operators and regulators are following the original guidelines to recover everything possible. In the Gulf of Mexico, operators and Federal regulators work on a case-by-case basis to ensure environmental compliance and decommissioning costs do not become unbalanced. BSEE is now supportive of leaving subsea wellheads in place (subject to fishing and naval issues) in case there a future problem with the well that requires intervention. BSEE does not support leaving the tree on the wellhead because it might be difficult to remove in the future. The “abandoned in place" option specifically follows regulatory requirements, amended or otherwise. The opportunity to abandon in place deeper than 800 m in the Gulf of Mexico is very evident. The information collected from participants in this study, regarding the final status of “abandoned in place” subsea decommissioned equipment, indicates that there have been a significant number of risers, flowlines, and umbilicals left on the seafloor.

 

Onshore Disposition

Participants in this study have had little input or experience with onshore disposition. Facilities are primarily chosen by the contractors, but must meet all regulatory mandates for safe handling and disposition. Contractors for disposal can be difficult to find. This is a cost driver, since anything that is pulled from the seabed must have proper disposal. Some questions related to contaminants in the subsea components and downhole pipe remain to be explored. These include normally occurring radioactive materials (NORM), mercury and arsenic.

 

Health, Safety and Environment

It is common practice by all operators to focus on Health, Safety and Environmental (HSE) issues and to encourage safe operations for personnel, vessels and equipment. One of the participants in this study shared concerns regarding HSE requirements for their contractors. The participant sent a safety rep onto the platform and ROV vessel in order to clearly convey to all contractors that they must follow the operator’s safety policies. In the future, this participant will have more kickoff meetings to review HSE issues with all contractors. Larger operators e.g. the majors, tend to employ Subject Matter Experts (SME) that physically inspect each element of the operation prior to mobilization. This includes vessels, ROVs, diving spreads, and each of their operational elements including cranes, DP systems, ROV redundancy, pressure vessels, and gas diving components. MODUs have come under significant pre-inspection criteria as a result of the Deepwater Horizon incident, including actual operation of the BOP system and related support apparatus.

 

Key Lessons Learned

Planning cannot be overemphasized. This includes identifying possible problems that might be encountered, and having predetermined solutions for the most likely problems. The operator must ensure that both the equipment, including the vessel and personnel are well qualified to undertake the tasks identified in the scope of work. In addition, the host facility should remain in place until all decommissioning work is planned. It may be needed for flushing and other tasks. An experienced decommissioning team, one with a thorough understanding of the field to be decommissioned, is essential to ensuring the project meets everyone’s expectations. Lastly, each P&A is unique. Do not underestimate the time required to compile and review documentation.

 

Conclusion

Subsea decommissioning is a growing segment of the industry in many ways. Older subsea fields and equipment are reaching the end of their expected service life. As a result, the decommissioning industry will follow a development path similar to the early development of subsea technology. It will move into ever deeper water and require better tools and new technologies to properly recover, seal and abandon seabed equipment in a cost effective manner. Cost control will be a primary driver balanced by the need to protect the ocean environment. Identifying, developing, and applying best practice from across the globe will help prevent future problems and secure the industry’s continued access to the deep oceans for resource development. It is critical the industry share best practices in order to reduce costs and to minimize the risk of pollution incidents in the future.

Note: After completing the Petrobras study, Endeavor Management identified a significant number of problem areas needing more study. The company has developed a Joint Industry Project offering to explore these topics. For more information please contact Bruce Crager at bcrager@endeavormgmt.com.

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What Low Oil Prices? The US Independents MayMake A Terrible Swing Producer

I

Reading Bill Barrett's press release out yesterday, you would never guess that oil prices remain 33% below the 5-year average.

The company announced it will increase its 2015 capex program by around 25%, put another drilling rig to work, and can generate 40% returns on new wells in the Denver-Julesburg (DJ) Basin at $65 oil. Its DJ Basin production is anticipated to grow in excess of 60% and 25% in 2015 and 2016, respectively.

Before we go any further, we must acknowledge that Bill Barrett is a small-cap E&P whose outlook should by no means be extrapolated across the entire US landscape. But Bill Barrett's news this morning is important - it shows a determination, nimbleness, and commitment to growth that should not be underestimated.

Swing Producer Or Grit Squad?

Following the November death of the OPEC put, a popular refrain around the industry has been "the US is the new swing producer." In its simplest form, the concept is that the onus is on the US oil production complex to correct lower now and balance the global market.

But the Independents clearly aren't on board with this notion. Embedded in their DNA is the need to keep drilling to offset production declines lest they self-liquidate. The growth model is one of self-perpetuation - drilling and producing serve the singular purpose of funding more drilling and production. Said more simply, the only reason to make money is so that it can be spent to make more, which will then be spent and so on. This MO is almost instinctual for most Independents, for those without it have already been weeded out.

Bill Barrett's announcement shows the rebellious grit that got the shale revolution started in the first place. 40% new well returns at $65 oil suggest that cost savings, improving rig and well productivity, and innovation can create acceptable ROIs and stimulate production growth in this oil price tape. The company's DJ Basin production is now anticipated to grow in excess of 60% this year and 25% next year. So while production growth is surely slowing (the rig count is down 50% from peak), productioncontraction is still not in the Independent's vocabulary.

Will Animal Spirits Prevail At $65 Oil?

Ultimately, it is possible OPEC could realize that much lower oil prices than $60-ish are required to really crush the shale grit squad and send unconventional oil production spiraling lower. OPEC itself may not be able/willing to intentionally withstand the price level and duration required. While OPEC's market share strategy looks like a sound strategic play in the short run, it is by no means a shoe-in in the long run.

In the days ahead, we expect more Independent E&Ps to begin to talk about how they are making wells work at $55-$65 oil. And some will begin to quantify the production growth they can achieve next year even with oil prices where they are today. These details will emerge before the November OPEC meeting, and we wonder how the ministers will respond as they set their course for 2016. If OPEC is truly committed to their market share cause, they could scrap the production quota all together, which while largely symbolic, should send NYMEX prices down at least 15-20% in very short order on headline value alone. Or maybe the animal spirits of the US Independents will take oil prices lower on their own.

The grit of the Independents, continued cost reductions, and improved rig/well productivity leaves us becoming more concerned about the trajectory of the anticipated US oil production decline that was defined by EIA predictions out earlier this week. Stay tuned, we'll be digging deeper into this issue in the weeks ahead...

Billy B Expansion Details

  • DJ Basin Well Return: 40% return calculated for an XRL well utilizing a 9,500’ lateral, 55-stage plug-and-perf completion, $6.25 million well cost, flat pricing of $65 NYMEX oil & $3.25 NYMEX gas and incorporates a $9/bbl long-term oil price differential.

  • Increased Budget: 2015 capex now planned in the range of $320-$350 million, up from the higher end of the $240-$280 million range previously. 2016 capex plan introduced at $225-$275 million, which assumes approximately 40 gross (32 net) operated XRL wells utilizing a two-rig drilling program at current service cost levels and is subject to board approval during the normal budgeting cycle.

  • Expanded Drilling Program: 28-32 net wells planned for 2015, up from 20-22 net wells in NE Wattenberg area. The increased activity will include adding a second rig in the NE Wattenberg area early in the third quarter of 2015 that the Company expects will spud an additional 11 gross (8 net) operated XRL wells in the second half of 2015. T

  • Funding: BBG announced a $100mm "at-the-market" (ATM) equity offering program, which it can draw on from time to time by selling its shares at its discretion to raise funds. Bill Barrett's previous capex budget was towards the higher end of the $240-$280mm range.

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