Needs more drillingConocoPhillips tells AOGCC about plans for improving Meltwater production ALAN BAILEY Petroleum News
It will be possible to improve oil production rates from the Meltwater oil field on the North Slope by using coiled tubing drilling to sidetrack some existing wells and by doing some well conversions, officials from ConocoPhillips, the field operator, told the Alaska Oil and Gas Conservation Commission during a July 9 hearing. The company has asked the commission to modify the existing area injection order for the field to allow the drilling operations. The company has also requested some other changes to the injection order, including an approval for some limited uses for injected water and a change to reporting requirements.
The change request stems from a problem identified early in the Meltwater field’s life, when ConocoPhillips experienced difficulties with a leak from the reservoir of fluids injected for enhanced oil recovery. Consequently, in 2012 the company placed an upper limit on the reservoir pressure, in expectation that the lower pressure would limit or eliminate the fluid loss. The new pressure regime appears to have cured the leakage problem, albeit with a drop in field production rates. The company says that its proposed new drilling program would improve production while also help to ensure that the fluid leakage does not restart.
Compartmented reservoir The Meltwater field lies within the Kuparuk River unit, to the south of the Kuparuk River field. Meltwater, which was discovered in 2000 and went into production in 2001, using the Kuparuk oil production facilities, has its oil pool in the Bermuda sandstone within the Torok formation, a part of the Brookian sequence, the youngest of the petroleum bearing rock sequences on the North Slope. The sediments that form the Bermuda interval were laid down as what geologists refer to as “turbidites,” a series of sand bodies deposited from rapid and short-lived sediment flows down the side of an ancient marine basin. Given this mode of deposition, and the way in which the sands tended to fill channels in the basin side, the sands tend to form disconnected layers and lobes, rather than occupying a continuous sand layer.
Initially, to boost Meltwater production, ConocoPhillips alternated water injection with the injection of miscible injectant, a mixture of natural gas and natural gas liquids used to flush oil from the subsurface rocks. But after the field’s water injection pipeline went out of service in 2009 because of corrosion, the oil recovery strategy changed to the use of just miscible injectant. Then, in 2014 ConocoPhillips switched to the use of just natural gas.
Injectant leakage The original version of the injection order that ConocoPhillips now wants amended was issued by the commission in August 2001, a few months before the Meltwater field went into initial production, Thomas Nenahlo, ConocoPhillips development engineer for the Meltwater field, told the commission during the July 9 hearing. Shortly after the start of the injection of miscible injectant, traces of injected material were found in the outer annuli of three wells, providing initial evidence for miscible injectant leakage. Apparently material balance calculations for the field have confirmed that leakage was occurring. A subsequent investigation led to various theories for the leakage and to a number of tests to try to prove a cause. And, starting in 2003, ConocoPhillips implemented measures to handle the leaks, including the installation of pressure monitoring equipment, monthly monitoring of well outer annulus fluids and special training for field operators, Nenahlo said.
Robert Wentz, staff geologist with ConocoPhillips, commented on the internal complexity of the Bermuda sandstone reservoir, with its discontinuous sand lobes. Those individual sand units within the overall sandstone interval are difficult to correlate between wells, he said. Eric Bressler, staff geophysicist with ConocoPhillips, showed a depth structure map and a seismic section that illustrated the complexity of the sand-filled channels and sand lobes. The isolation of individual sand bodies in the interval results from the chaotic nature of deepwater turbidites, he said.
Production data from the field indicates poor fluid connectivity between individual sand lobes, Bressler said.
Leak investigation Wentz described a study of rocks above the Meltwater reservoir that ConocoPhillips had conducted between 2012 and 2015, to characterize these “overburden” rocks and better understand how fluids may have leaked into the overburden from the reservoir. The results of this study, somewhat hampered by a shortage of data about the rocks, turned out to be inconclusive from a data analysis perspective. However, modeling supported a view that the loss of fluids from reservoir resulted from a large pressure differential between injection and production wells, prior to the impositions of a pressure limit, he said. That high differential can be attributed to the poor fluid connectivity between wells.
A 4-D seismic analysis - essentially a comparison between two 3-D surveys done at different times - revealed linear features in which the gas saturation or pressure in the reservoir had changed, Bressler said. Further analysis of the data showed that these features must result from rock fractures as well as from gas behavior, he said. It seems that, under the impact of high pressure differentials, fluids leaked by migrating upward through fractures in the overburden, Nenahlo said.
Reduced pressure Nenahlo said that ConocoPhillips implemented two initiatives to contain the loss of fluids. First, to reduce the observed high pressure differential between injection and production wells, the company imposed a pressure limit of 3,400 pounds per square inch at the interface between the base of the injector wells and the surrounding sand, with several surveillance programs put in place to monitor the effectiveness of the pressure limit, he said. Second, the company implemented a fluid containment assurance program.
In May 2013 AOGCC issued a revised version of the area injection order for the Meltwater oil pool, Nenahlo said.
More drilling Now, based on ConocoPhillips’ experience of operating the Meltwater field, and with the surveillance programs showing no further fluid leaks since the pressure limit was applied, the company wants to further amend the injection order for the field, allowing coiled tubing sidetrack drilling and conversions of some production wells to injectors to further reduce the risk of the loss of injected fluids, while also optimizing ultimate hydrocarbon recovery from the field, Nenahlo said. Essentially, the program would place injectors and corresponding producers in the same sand bodies within the reservoir, rather than straddling sand body boundaries, thus enabling higher production rates without raising the injection pressure to levels where fluid leakage would restart.
Coiled tubing drilling involves drilling out from the side of an existing well bore using a continuous length of small-diameter, flexible pipe.
Currently the Meltwater field has 13 production wells and six injection wells, Nenahlo said. He said that some of the producers and injectors are not in optimum locations in relation to the disposition of the various sand bodies, especially in the southwestern portion of the reservoir. In response to a question from Commissioner Dan Seamount, Nenahlo commented that improved access to one part of the field might require the drilling of a new well from the surface, rather than a sidetracked well.
Asked by Commission Chair Cathy Foerster about the feasibility of using hydraulic fracturing to improve fluid communications between injectors and producers, as an alternative to the drilling program that ConocoPhillips proposes, Nenahlo said that the distances between the wells in the reservoir is too great for the hydraulic fracturing approach.
Other requests ConocoPhillips is also requesting permission to inject some seawater or oilfield produced water into the Meltwater reservoir for use in surveillance and well maintenance operations. An earlier version of the reservoir’s injection order had allowed the injection of similar water for improved oil recovery, Nenahlo commented. The company is also asking that the reporting frequency for the field be changed from monthly to annual, an arrangement that the company says would continue to ensure the continued regular transmission to AOGCC of information about development and containment issues. And, with the leakage of fluids from the field stopped and optimum hydrocarbon recovery achieved, ConocoPhillips is asking that the termination date be removed from the injection order, Nenahlo said.
Foerster said that, in recognition of the changing circumstances that tend to surround oil fields, the commission is considering mandating a termination date for all area injection orders, an arrangement that would presumably apply to Meltwater should the commission decide on this new rule.
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