It is often said that ‘necessity is the mother of invention’ and there are plenty of examples of this, ranging from the eBook, which physicist Joe Jacobson created when he finished a book he was reading and realised he hadn’t brought another to Japan’s need to produce high quality consumer goods to stabilise its economy post-WWII, driving the modern quality revolution.
The oil and gas industry is no different. Philippe Charlez, Senior Technical Advisor at Total, was quoted recently as saying “Bad economics can be a strong booster of technology”. However, this isn’t the first time that the oil and gas industry has seen hard times boost a technological revolution, for example, the late 1970s oil crisis brought about a huge increase in the number of patents created for development technologies. Today, in the lower for longer environment, the industry is going through another period of technological change. The result is both the emergence of new ideas and the better application of existing technology, bringing forth an integrated evolution. This is not about ‘cheap-and-cheerful solutions’ or bargaining a better deal on an FPSO; it is a rethink of convention coupled with a much better understanding of the subsurface, to bring about robust economic returns, even in deep water during a lower for longer, and potentially forever period of time for the oil and gas industry.
Not going for every barrel
Early in 2017, BP announced it would go ahead with plans for Mad Dog 2 in the Gulf of Mexico. The price tag on the project initially came in at $22 billion in 2003 but has since been reduced by more than half to $9 billion. Some savings are due to deflation in costs of services since the downturn, but this is only one part of the story. The real savings came about when BP went back to the drawing board and found an economic solution that differed from its original strategy to try and produce every barrel. Initially when BP revisited the development they planned to produce about 90% of the resource for 66% of the original development cost. Then, using a combination of technology and planning, they expect to recover 100% of the resource for 50% of the original development cost.
BP believed Mad Dog 2 would not have been economically viable without the use of four key technologies: “seismic imaging and processing along with an ocean bottom node survey for understanding the reservoir, immobile proppants to maintain the sand pack in injection wells, low-salinity water injection to boost recovery rates, and lazy wave risers to decouple the motion of the risers from the vessel and improve the fatigue life of the risers.” Most striking is that all, except the last, of these innovations are reservoir focussed technology. This utilisation of innovative reservoir techniques will only continue to propagate as necessity demands better solutions. Once considered as exotic and expensive solutions, reservoir-centric technologies like low-salinity water injection, will only reduce in cost with time, as Wood Mackenzie notes.
First impressions last
BP is proudly broadcasting the financial benefits in the billions of dollars range that it is realising through the use of better seismic visualisation: for example, an additional 200 million barrels of oil were added to its resources within the Atlantis field in the Gulf of Mexico. A new method for acquiring seismic, with longer offsets increasing the quantity of data available to be processed, and using a newly developed algorithm that works faster than before, is credited for the improvement. This algorithm also allows BP to find resources below salt domes.
Moving from static to dynamic perspectives, there have also been vast improvements in electromagnetic (EM) technology used to visualise fluids. EM surveys are not new, they have been used since the dawn of the oil industry, first run in the 1920s by Conrad and Marcel Schlumberger. However, the modern EM survey provides 3D and 4D images of the fluid in the subsurface and can be used to find bypassed reserves and define fluids in place. Movement can also be tracked and the front of fluid movement after production has begun can be visualised by separating resistors (oil, gas and CO2) from conductors (salt water, steam and chemicals). Providing a step between seismic and direct well fluid measurements, the applications to exploration, development, production and monitoring are immense.
Profiting from “downhole jewellery”
On the face of it, smart wells appear to be the way forward. However, without conditioned objectives or adequate tools to digest the wealth of data, there is a risk of overwhelming day to day operational decisions. Modern wells are laden with more sensors and control than ever before. An example would be Tullow’s TEN (Tweneboa, Enyenra, and Ntomme) field in Ghana, West Africa, where its development plan was driven by operational requirements and the need to monitor and control. Tullow chose smart wells equipped with “downhole jewellery” which allows zone by zone monitoring and control. This enables close observation and optimisation of operations by producing, injecting or isolating zones using sliding sleeves as frequently as desired and limited only by the turn-around time of the reservoir engineer.
The future of these digital oilfields will be a truly integrated solution whereby all constraints from every discipline can be reduced to a complex objective function, which can be used to drive operational decisions in accordance with the defined value drivers. These operational decisions must therefore be made with a holistic view of the field. Short-term problems causing downtime, such as leaks and safety concerns could be managed alongside medium-term challenges such as effective zonal drainage and pressure depletion. Long-term applications will proactively use the information to maximise recovery and determine the best future well locations, completion workovers and further CAPEX investment. Taking a continuous approach to what-if analysis brings the next level strategic approach to reservoir management. We can only wait in anticipation that this will lead to an emphasis on effective multidisciplinary teams.
Starting with the end in mind
Reservoir focussed technology enabled a bold set of ideas to create an economic field development plan for the Libra field, offshore Brazil. This is one of the largest of Brazil’s offshore pre-salt plays containing 7.9-15 billion barrels of oil. One major challenge to developing this field was the 45% CO2 production gas. Flaring the gas was not an option, neither was piping the gas to shore, given the 200km distance. The solution was to put the CO2 back into the reservoir. Whilst it might seem an expensive solution at first glance, the reinjection will increase recovery and keep costs below $35 per barrel.
Reservoir studies allow the injection of gas to take place in optimised cycles, and maximise benefits from the miscible zone of CO2, to increase reservoir sweep and recovery. Usually CO2 Water Alternating Gas (WAG) is expensive and uncommon offshore; on Libra, costs were reduced by using the same injection line to push water and CO2 into the reservoir and use reservoir pressure to reduce the load on facilities in the gas-oil separation process.
Innovation in the reservoir starts with powerful thinking
Reservoir-centric innovations and fresh ideas are enabling operators to maximise their return on investment and ensure projects are economically viable. These improvements have been driven out of the extended low oil price environment, but will undoubtedly change the face of the industry for good.
At io, we are challenging traditional ways of thinking, being disruptive and leading the way forward with a fully integrated technical-commercial-strategic approach. We have a wealth of experience and a collaborative mindset that leverages experience and innovation to deliver value to our clients.
To find out how io can help you understand your reservoir with greater certainty, contact us at email@example.com.