Africa (Sub-Sahara) ExxonMobil will drill its first exploratory well offshore Liberia this month, the company announced on 18 October. A deepwater well is planned on the Liberia-13 Block, which is about 50 miles off the coast of the West African country. Solo Oil plans to spud the Ntorya-2 appraisal well in Tanzania next month. The drilling pad is a mile southwest of the 2012 Ntorya-1 discovery well, which was tested at rates of 20.1 MMcf/D of gas and 139 B/D of condensate. An independent report estimated the discovery to hold 153 Bcf of gas in place, of which 70 Bcf is considered a gross best-estimate contingent resource. A gross best estimate of more than 1 Tcf of gas in place has been made for the Ntorya prospect as a whole, in which the company has a 25% interest. Asia Pacific BP has decided to abandon drilling plans in the Great Australian Bight offshore southern Australia, an area in which prospective drilling has long been contested by environmentalists.
Creativity and innovation have long characterized production and facilities, and this year is no exception. Much of the work reported this past year was conducted during the recent period of low oil prices. The economic challenges of the oil industry clearly have provided a strong stimulus for even more creativity and innovation. The use of big data and analytics appeared in a number of papers with an emphasis on the use of artificial intelligence (AI) for building databases used to monitor the health of equipment and structure risk-based-inspection (RBI) strategies. Monitoring data inputs from thousands of sensors (paper OTC 28990) allows an AI application to predict an impending failure and notify operators by text or email when the incipient problem is detected so that proactive maintenance can be scheduled to avoid an unplanned shutdown or catastrophic failure.
Seismic velocity in salt domes in the Gulf of Mexico varies due to sediment inclusions and sutures. Typically, seismic velocity of salt is slower than clean salt velocity: the maximum slowdown can be more than 20%. Therefore, it is extremely important to build a velocity model with variable salt velocity to improve the base salt interpretation, subsalt imaging and better well ties at the subsalt level. Using different seismic attributes (envelope, root-mean-square amplitude, absolute amplitude, gradient, and others) as inputs, a neural network classifies a seismic image of a salt body into a set of classes. Different classes are mapped to different salt velocities. The scalars used in the mapping are adjusted using the sonic velocity inside of the salt as calibration and the base salt tie to the well markers on seismic images. This workflow was applied to a large reprocessing project in the central Gulf of Mexico; this method has been proven to be effective and efficient, resulting in improvement in base salt events and substantially improved subsalt imaging as well as base salt well tie, all while offering improved turnaround time.
Presentation Date: Wednesday, October 19, 2016
Start Time: 2:20:00 PM
Presentation Type: ORAL
Ocean bottom node (OBN) SRME that combines OBN and streamer data is known to be an effective way to predict surface-related multiples in OBN data. However, the available streamer data often have limited offset/azimuth coverage. Additionally, the double source wavelets due to the convolution of OBN and streamer data limit the bandwidth (loss of low and high frequency) of the predicted multiples. OBN model-based water-layer demultiple (MWD) overcomes such limitations and is a good complement of OBN SRME; MWD replaces the streamer data with the water-bottom Green’s function that has no offset/azimuth limitation and keeps the full bandwidth of the input data. With Gulf of Mexico (GOM) OBN data over the Atlantis field, we illustrate the benefit of joint SRME and MWD over SRME alone with the improved attenuation of low-frequency multiples and water layer-related multiples.
Presentation Date: Monday, October 17, 2016
Start Time: 3:45:00 PM
Presentation Type: ORAL
Offshore Cost Cuts
Offshore drillers have been battered by the plunge in oil prices with falling day rates and a growing number of older rigs headed for demolition.
Lower oil prices added to the pain of a down market due to a glut of drilling capacity. A wave of new, efficient drilling rigs coming into service created an oversupply that has been magnified by more productive drilling operations, said Bob Fryklund, chief upstream strategist at IHS Energy.
He said day rates for new contracts are off by more than 50%, with rigs once commanding day rates of USD 650,000 now leasing for USD 250,000, he said. For oil companies, “it is a good time to renegotiate contracts. It is a bad time to be on the other end,” Fryklund said during a presentation at the 2015 Offshore Technology Conference (OTC).
Drilling rigs are the highest profile target for cost cuts, but “operators are seeking reductions in the cost of most things,” said Andrew Meyers, a manager at Douglas-Westwood, which provides market data and consulting services for companies working offshore.
This low-cost environment is expected to linger. It could take until 2018 for the rig market to tighten enough for rates to recover, said Thomas Shattuck, a research analyst at Wood McKenzie.
But when the oversupply passes, the cost of offshore services will rise again. Lasting cost control will require companies to rethink how projects are run to eliminate inefficient methods that add to the cost of the complex multibilliondollar developments.
“You can cut costs a certain amount but efficiencies that increase productivity are likely to have a benefit that lasts into the next up cycle,” Fryklund said. There is fat to cut. Even when oil was still selling for USD 100/bbl, operators were saying fast-rising costs were eroding margins.
“There have been a lot of inefficiencies in the market for a long time,” Meyers said. The problems include soaring project management costs. Multiple design teams can create incompatible systems requiring costly changes. One sign of the times is the rising number of joint ventures between large offshore service companies that promise to bring together a wider range of experts into teams that look at the larger picture.
“There is a little rethinking of project development,” said Imran Khan, a senior research analyst covering the Gulf of Mexico at Wood Mackenzie. “It is a challenging environment economically and technologically. Low oil prices offer a strong argument for doing things differently, but are not the only motivation for change,” he said.
It is still too early to know if things will change, but the record of past costcutting efforts have been spotty. “What I understand is with every downturn, the major operators talk about savings (on project development), but they never materialize,” Khan said. “This time, they say it is different. Time will tell.”
Waterflooding can supply additional reservoir energy for producing substantial quantities of oil trapped due to limited displacement drive and poor sweep efficiency. However, water injection is not commonly used in the deepwater Gulf of Mexico (DW GoM) due to good primary recovery, drilling cost and facility limitations. In over 80 fields and 450 reservoirs, water injection program has been implemented in only 18 reservoirs in 13 fields, or less than 5% of potential waterflooding candidates.
DW GoM mid-Miocene reservoirs are characterized by sparse well counts, over-pressured, and generally good rock and fluid properties. Rock compaction and moderate aquifer influx often provide moderate to good natural drive energy and oil recovery. Primary oil recovery averages 32% with the 80% confidence range between 16% and 48%. However, Paleogene reservoirs are characterized by deeper depth, high pressure, high temperature, complex geology, and rock and fluid properties. Estimated recoverable oil is only 10% of OOIP assuming primary production and limited natural drive energy. Water injection programs will be difficult to execute in tight, abnormally-pressured Paleogene reservoirs. Waterflooding of deepwater turbidites has accumulated many lessons and learns now, and a comprehensive understanding of the influence of depositional environment and injection into over-pressured, highly compacting rocks is necessary. This paper is a detailed examination of Pleistocene-to-Upper Miocene age turbidite reservoirs in the DW GoM under water injection. Issues on waterflooding these deepwater plays were reviewed in the context of geological setting and depositional environment. Despite many drawbacks that tend to oppose the implementation of a waterflooding in Paleogene reservoirs, this paper still proves that they are candidates for water injection programs under the rules of good production practice. Moderate oil recovery is suggested in highly compacting reservoirs with supplemental injection drive. Overall, waterflooding strategies have proven to be highly effective in achieving good incremental oil recovery from the deepwater Gulf of Mexico reservoirs.