Raising production efficiency in offshore gom

From Data to Decision: Barriers to Optimizing Oil Production with Analytics

Raising Production Efficiency in Offshore Gulf of MexicoBy Alex Cherry, Industry Analyst at Upstream Intelligence

In the fall of last year Upstream Intelligence conducted over 40 research calls with operators, service providers and consultants in order to learn more about the oil and gas production challenges in the United States Gulf of Mexico , as well as the approaches and technologies being developed to overcome these. This whitepaper presents the research findings in order to instigate the development of new solutions throughout the oil and gas industry.

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In conjunction with the Offshore Production Efficiency Conference, Houston, 16th-17th June

Join 150+ top production and intervention experts from GoM’s leading operators and contractors. Check out the Offshore Production Efficiency Conference brochure here to develop optimization strategies for your Wells, Reservoirs and Facilities


The Great Crude Plunge: 2014 – ?

Since late June 2014 the price of Brent crude has fallen more than 50% from a high of $112/barrel to its current level in the $50-60/barrel range. This is underpinned by factors both on the supply side and the demand side that have led to between one and two million BPD excess oil on the global markets.

• In the past decade record output from shale formations has doubled US crude oil production to over 9 million BPD.

• The Saudis have ramped up production in what many people see as a way of retaining market share in the face of rampant US shale, although it may also be designed to hurt the Assad regime in Syria. No production cuts were agreed by OPEC in its meeting last November, even with oil-exporting economies floundering.

• Global demand for oil has not met expectations, with sluggish growth in China and India.

Considerable oil inventories have built up and more scheduled production has been brought on line, so it looks like it will take a period of time for the slack in the market to be taken up and prices to rebound. Predictions for the ultimate duration of the slump vary – and analysts after all failed to predict it in the first place – but the consensus is that low prices will endure until the end of this year at the earliest and may not return to their prior $100/barrel level for a few years. There are many factors at play though and some commentators even see in the current climate of cuts the makings of an acute price spike down the line.

Operators need to strike a difficult balance between long-termism and short-termism and be prepared not only for an extended lean patch but also for the upswing when this does eventually occur. This entails a rethink of both CAPEX and OPEX strategies. Oil companies big and small have announced big-headline CAPEX cuts for 2015: Total by 10%, Exxon and Chevron by 12%, and BP and ConocoPhillips by 20%, while Shell pledged to cut $15 billion over the next 3 years. Before considering what other approaches are available, let’s take a quick look at recent production trends in the GOM.

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Production Trends in the GOM

Offshore production in the GOM has long been heading further out to sea: the first fixed platform went up on the continental shelf off the coast of Louisiana in 1947 but since the 1980s production has been moving progressively into depths greater than 1,000ft. With deepwater production (defined as 1,000ft – 5,000ft) plateauing, the continued rise in production has been due to ultra-deep developments (>5,000ft below the surface).

The deepwater fields in the GOM are spread over the Upper Tertiary (Miocene) and the deeper Lower Tertiary (Paleogene). Paleogene reservoirs, long hidden underneath layers of impenetrable salt, have often turned out to be larger than their Miocene counterparts and therefore represent enormous prizes. This has attracted great interest from prospectors as new technologies have emerged for scanning sub-salt reservoirs and operating at depth. However, development of these reservoirs has been beset by enormous equipment costs and volatile production rates, and this even before the price slump. Some of the issues operators have faced in producing these reservoirs have included:

Reservoir modeling: despite advances in technology, sub-salt reservoirs are fundamentally harder to map than pre-salt. In several fields engineers have been caught out by unexpected reservoir behavior, like compartmentalization and loss of pressure support.

Flow assurance: hydrocarbons tend to misbehave under extremes of pressure and temperature, and nowhere are these extremes as pronounced as in the GOM deepwater. Hydrates for example can form at the high pressures and low temperatures found on the seafloor and lead to anything from blocked pipes to compromised wellbores.

High skin factor: while large reserves may be available, this is of little use if they cannot make it into the wellbore due to compromised permeability of the near-wellbore region. This is often due to high-pressure overbalances during the initial drilling phase.

Logistical difficulties: onshore and shallow water wells can be monitored and intervened on with relative ease. This becomes more difficult the further from the shore and the deeper a well is located, especially if wells have subsea completions and no downhole data-gathering or actuation systems.




The chart above from McKinsey shows the different cost factors contributing to the cost per barrel of oil in different deepwater basins. As this shows, ‘well productivity’ and ‘water and drilling depth’ are, in relative terms, more of a problem in the GOM than elsewhere. As companies become more experienced, and potentially specialized, in different basins there will be greater potential to address these issues of high drilling cost and suboptimal production, the adverse impact of which has been partially masked by years of high oil prices. If necessity is the mother of invention, then perhaps there is no time like the present for innovations in these areas.

Cash-Flow Problems at Oil MajorsThe fall in the oil price from mid-2014 onwards is devastating not so much for its impact on the future profitability of offshore projects – after all, these become profitable based upon future, not present, prices – but for its effect on current company cash flow, and it is with this that companies pay their service providers and contractors. Companies don’t just need cash to cover new CAPEX projects, they need it in order to meet all their outgoings, including OPEX for producing assets, dividends for shareholders, taxes and debt repayments (especially for smaller, more leveraged independents). When oil prices fall, oil producers can find themselves hard pressed to meet these obligations – and this is precisely what has happened.




While the long-term health of oil companies relies upon the discovery of new fields and the development of the technologies to exploit them, they still actually have to survive from year to year with intact finances. A common kneejerk reaction is understandably not to cut their dividend payments to shareholders but to cut expensive E&P programs, which do nothing to resolve present-day issues with cash flow. Even if a vast new field will be (probably) profitable at 2020 prices, you cannot start to develop it in 2015 if you have nothing to pay your drillers with (let alone your shareholders)! Oil majors’ current cash-flow issues can actually be traced back as far as 2011-12. As can be seen in the graph below (relating specifically to Shell), from 2011 onwards the rising oil price (due to increasing global demand for oil) did not actually keep pace with the rise in CAPEX required to produce it.

As a result of these trends some CAPEX cuts were actually being announced in 2013 for 2014, well before the on-going drop in the oil price. After a period of extravagant spending (justified by an expectation of future price), oil companies now find themselves in what looks like a protracted period of lower prices and are coming under more and more pressure from investors, who want both dividends and greater fiscal discipline. It is oil dividends that make oil stocks, a favorite of pension funds, attractive in the first place.

So we ask ourselves: what approaches can operators take against a backdrop of fallen oil prices, recently high drilling and equipment costs and a raft of chronic operational issues? Seen from a high level, there appear to be three primary areas that operators can focus on: reducing CAPEX, boosting production from existing assets and reducing overall OPEX.




Strategy 1: Slash CAPEXThings like taxes and dividends cannot simply be cut out, so a company’s immediate savings come from a reduction in optional expenditure, that is, by cutting new exploration and drilling projects. As mentioned earlier, most oil companies have now announced significant cuts in their CAPEX budgets and several major projects are on hold (proven reserves are safe in the ground and, unless they have to, operators do not want to sell these at a poor price).

Despite the environment of cuts, it stands to reason that whoever can maintain their frontier developments will be well placed to take advantage of an eventual bounce-back in oil price. By this logic, some companies are taking bullish bets on the long-term profitability of offshore projects (which is predicated upon long-term, future prices). So there’s no point waiting for high oil prices if, when they arrive, you have no fields to on-stream or engineers to on-stream them with; and if everyone else is cutting their current investment in future projects, then the bounce-back could, at least in theory, take the oil price back up higher than it was before. This has led some commentators to suggest that majors may preferentially scale back onshore shale due to its shorter time-to-market and leave their offshore and deepwater developments to plod along with an eye on a more supply-constrained future; if there is a resurgence in price, shale can be brought back on-stream in less than one year, whereas deepwater projects may take up to a decade to reach maturity.

So even though E&P spending is the hardest hit category at operating companies, this is being scaled back rather than ceased entirely.

Strategy 2: Boost Production EfficiencyWhile it may seem paradoxical – one half of the problem with the oil price is the glut of supply – even in low-price environments, more oil still yields more revenue (revenue being simply the product of oil price and oil quantity). If operators can increase the production efficiency of their existing assets, these will deliver greater marginal profits, which will go some way towards improving operators’ cash-flow situation. In a survey conducted last month by the Upstream Intelligence team, 2/3 of respondents considered optimizing production from existing assets to be a high priority.

Question: In the current oil-price climate, how much of a priority is optimizing production from existing producing assets?

Source: Offshore Production Efficiency Survey by Upstream Intelligence

Low

Medium

High

3%

32%

65%

$




More oil isn’t going to come from fresh E&P, firstly because this is being scaled back and secondly because it takes so long with a new field to reach first oil; the only sources of new oil are therefore existing producing assets (broadly termed brownfield, although they do not have to be legacy fields). And thus the old adage holds true: the best place to find oil is in the oil field!

Optimizing existing production is easier said than done, as it is generally a matter of balancing investment with likely risk and return so that the overall Net Present Value (NPV) of a field increases. What makes this an appealing strategy is that upfront field costs – the production infrastructure and the well itself – are sunk and that operators’ understanding of a field increases over time, allowing them to apply insights that weren’t available when the wells were first brought on line. Broadly speaking, operators can look to increase inflow (the amount of oil available from the formation) or outflow (the efficiency with which this can be moved out of the well and through the pipes). Operators are resorting to a greater use of data, analytics and visualization software in order to understand what the maximum production potential of their fields and wells is on a daily basis and where the best wells and zones are located.

As touched on earlier, plenty of offshore wells are saddled with a high skin factor which limits inflow. This can be remediated to an extent through acidization. Outflow can be increased through application of artificial lift (like gas lift or ESPs) and advances in flow assurance management to banish asphaltenes, hydrates and paraffins from the pipes and prevent slugging. None of these interventions comes for free however and each one has its cost and logistical implications, so it is more important than ever to quantify accurately the volume of incremental oil on offer and the risks of reaching out for it. In some, but naturally not all, cases the breakeven cost of interventions can be lower than the breakeven cost of new drilling, plus existing wells deliver profits today as opposed to in 5 years’ time.

These logistical difficulties and risks are particularly acute in the case of subsea wells, where there is no direct access to the well from the surface. Drilling rigs have historically been used in these cases but the associated cost of doing this often skews the economics too far to be profitable. However, to back away from the challenge of subsea well stock is to back away from a sizeable prize. Our Offshore Production Efficiency survey showed that subsea wells are where the greatest upside is perceived to lie.

Question: Where are the biggest opportunities for incremental production from existing producing assets?


Subsea Wells

Dry-tree wells

Platform Wells

61%

14%

25%




The incremental reserves on offer in existing subsea wells are one of the factors driving interest in more cost-effective forms of well intervention, such as thru-tubing work and rigless/riserless intervention (RLWI). Before workovers become the new drilling though there are a number of concerns the industry must yet overcome in critical areas like well access, well control, well integrity, scope of work, staff competence and the availability of suitable intervention vessels and equipment. However, the potential is there to fundamentally alter the entire economics of E&P, which at the current price is stacked heavily against operating companies– so watch this space!

Strategy 3: Reduce OPEXAs we have discussed already, CAPEX can be slashed and producing assets can be made to produce more, two ways for operators to make their overall cash-flow situation healthier. Another area where savings can be made is in the realm of day-to-day operations. OPEX cannot be reduced like CAPEX by slashing projects but rather through people learning to operate their assets more efficiently.

Offshore assets encompass a wide range of things, including wellbores, pipelines, subsurface architecture and topside facilities, and even small percentage improvements in how these are managed can, if applied uniformly, yield large cost savings. Plenty of downtime is caused by equipment breakages and the associated wait-time for replacement parts and installation. Massive one-off costs can be incurred by allowing well integrity issues to snowball, and indeed whole wells can be permanently lost as a result, with an understandably disastrous effect on overall production. These are just two areas where a more proactive approach can have a major long-term impact.

Predictive maintenance is an increasingly appealing strategy for managing equipment failures, especially in the case of subsea integrity where individual parts are not only system-critical but difficult to access and replace. There are reams of data being generated daily about oilfield equipment and the conditions in which it operates, and operators have historically not used this to their best advantage— namely, to identify potential cost savings and productivity improvements.

As far as wellbore integrity is concerned, it can be better to manage small issues on an on-going basis than to be overtaken by the need for recompletion, which is a massive one-off cost. Desire for more cost-effective intervention practices (like RLWI) is being driven not just by the need to better and more regularly stimulate subsea wells, but also the need for more options from an integrity management perspective.




2015: A Transitional Period?

While some companies will have stronger balance sheets than others, the challenge in the current climate is not simply to scrape through but to create competitive advantage in a landscape which is straightened for everyone; it is easy to think that competition is only for the boom time but it applies now as fiercely as ever. So those companies that can generate good cash flow despite the low prices will be able to keep more of their operations up and running, place bullish bets and make strategic ‘bottom of cycle’ acquisitions in time for the inevitable rebound in crude prices, whether that is in 2016 or 2020.

We have covered here three broad strategies that operating companies might take. In reality it will always be a mixture of these and others that apply, and operators need, more so than usual, to take a holistic approach and share data and insights across operational silos. How this happens – whether through forging partnerships or implementing internal value loops – will vary from operator to operator.

Question: Where are the biggest technology gaps for ensuring efficient field production?


It is clear that there is no silver bullet for operators’ concerns in the current environment and that there are still numerous technology gaps that the industry as a whole needs to work on over the coming years (see above). The present is a time for efficiency-finding and innovations, out of which the whole industry will ultimately emerge both more resilient to future shocks and more sustainable in the long run.

61%

21%

33%

18%

58%

46%

30%

28%

4%

Downhole data-gathering

Downhole actuation

Well access systems

Thru-tubing tools

Well Stimulation...

Flow assurance management

Subsea controls

Light support vessels

Other

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Date post:	13-Apr-2017
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Raising production efficiency in offshore gom

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