Two wells on the maturing Marathon Oil-operated Beinn gas and condensate field in the North Sea have been subjected to close evaluation to see if recovery could be improved.

After the formation of a joint venture with a contract partner involving an element of risk and reward, a once shut-in well has resumed production after problem zones were isolated and a fracture treatment applied.
The first well into the Beinn reservoir, B20, was drilled in November 1992. Three additional wells were drilled by 1995.
Beinn's Middle Jurassic reservoir is deeply layered and characterized by moderate porosity and low permeability. "It is not a normal North Sea layer," said Bruce McIninch, production engineering supervisor for Marathon. "We knew it would be difficult to get good recovery from the laminated reservoir."
The operator felt the Beinn gas and condensate reserves were worth pursuing. But as water isolation and hydraulic fracture stimulations were attempted in an effort to get the best possible performance out of the field's four production wells, productivity failures reduced the prospects for optimal reserve recovery.
After water fracture treatments, McIninch said, "we saw an attractive rate improvement and a pretty normal post-fracture decline in well B20, and we have had varying degrees of economic success with the fracture treatments in other Beinn producers."
A second Beinn well, B21, experienced water production in late 1999, and intervention was required to try and improve performance. Another well, B23, also was tapping the field, but its performance was declining, too.
A 3-week platform shutdown took place in the summer of 1999, but oil production from Beinn never returned to its previous levels. "(B23) was producing pretty good but just would not flow after the shutdown," McIninch said. "We wanted to get both B21 and B23 back on production since we felt the reservoir was not depleted."
Isolating the problem
That was when drilling and reservoir teams started to think hard about their future strategy. Well intervention was considered to obtain better diagnostic data.
"We knew it would be costly to intervene with coiled tubing," McIninch said.
Marathon felt the shut-in wells might provide the data required, but the cost of getting the data had to be justified. Thus the scene was set for a well investigation program. An economic case for obtaining more reservoir data existed, but the cost of getting that information had to pay off with knowledge that would allow better hydrocarbon recovery in the future.
Building a partnership
Marathon approached Schlumberger to see if the service company was interested in running a new data acquisition tool, the first step toward improving Beinn's performance.
McIninch said the key to the proposal was for Schlumberger to accept "some risk in the costly data acquisition phase, and in return we allowed them to continue problem solving into the (project's) solution phase."
Schlumberger deployed its Production Services Platform (PSP) tool suite, which includes the Ghost (Gas Hold-up Optical Sensor Tool), used commercially in the North Sea since 1999.
It normally is run on wireline and gives a more complete understanding of the production flow profile, indicating more precisely where oil, water and gas are coming from within a reservoir by providing multizone analysis.
"We are also looking at the reservoir behind the pipe by performing analysis behind casing and using it to tell us more about reservoirs we are not currently exploiting," said Sunil Gulrajani, an account manager for Schlumberger.
McIninch said the tool allowed his team to get to the next evaluation stage, with more certainty about their remediation plan.
"Our concern was that the water was moving up through various sand stringers (in the wells). The question was whether we would be able to find these stringers and isolate the water."
Marathon engineers were able to place the logging tools right into the individual oil, water and gas concentrations within the Beinn reservoir in well B21. The tools were in the hole for 8 hours, and the well was flowed so that the different phases of flow could be measured.
"After running the PSP, we knew exactly where the water and hydrocarbons were coming from. The picture was much more clear than previous PLT logs," McIninch said.
Schlumberger tools work with electrical and optical probes to measure flow. They are based on the principle that a saline solution has a higher level of conductivity. The PSP tool uses this parameter to measure the varying electrical signals generated from its electrical sensors. Optical sensors measure how much light is refracted back to the source. Since produced gas contains bubbles, more light is refracted, allowing the tool to measure the gas phase within the production flow as well.
Selecting a treatment
Four reservoir sections - H1, H2, H3 and H4 - were evaluated.
From the data obtained by Schlumberger, both parties agreed H4 and H3 were producing the most water, and the partnership decided to plug back those sections. Schlumberger also recommended a fracture treatment of the H1 zone to increase the rate of flow and further enhance recovery.
"Logs indicated that H1 was not producing as much as we hoped, and H4 was producing a sizeable amount of the total production. We both agreed it was worth the risk to try and improve the rate and recovery with a hydraulic fracture treatment," McIninch said.
This was a departure from general practice in the UK North Sea, he said, where reservoirs rarely require this kind of treatment. Gulrajani added fracture treatment is being used more in Norwegian reservoirs. "More and more we are getting into mature assets with bypassed recovery which is localized due to low permeability. This is where an engineered fracture treatment, such as PowerStim, can make a difference," he said.
The diagnostic process led to the selection of a hydraulic fracture treatment to stimulate the reservoir. Consequently, the Schlumberger purpose-built marine stimulation vessel, Big Orange XVIII, was deployed alongside the Brae Alpha platform with dynamic positioning to conduct the operation. ScaleProp, a proppant impregnated with scale inhibitor, was used to enhance the conventional fracturing process, ensuring long-term protection within the fracture from potential scale precipitation.
Getting back to production
Following the application of the contractor's solution, well B21 has since produced 10 MMcf/d of gas, about 600 b/d of condensate and no water.
An innovative lift-log procedure was required to gather data from well B23 because it would not flow. "We did not really know why the well initially stopped flowing when we had the platform shutdown," McIninch said. Inert nitrogen gas was used to lighten the fluid column and flow the well while log data was collected on memory. Making this application on B23 unique was the first-time use of PSP on coiled tubing in a live well with nitrogen and memory - to provide real-time production data from the well flow.
"What we found was that there was some water production coming from the lower interval, H4, and we wanted to get this isolated, but the data was not as conclusive as on B21." Again, Marathon elected to plug back and isolate the lower stringers. But this time, there was not enough data to confidently use a fracture treatment. Prior to the shutdown, this well had been producing about 800 b/d of condensate and 15 MMcf/d of gas. Marathon chose to risk an acid treatment in an attempt to remove scale from the perforation and reopen the channel to the reservoir. "We were not successful with that treatment," McIninch said. "After the frac success in B21, however, we are currently considering a return to B23."
Reaping the Benefits
McIninch feels that Schlumberger involvement allowed Marathon to reduce its exposure to the risk involved in a costly and sophisticated intervention and data-gathering exercise that might not have paid off. "We think we did the right thing to bring somebody else on board to reduce the risk, and reduce our total exposure," he said. "On B21, it gave us a better feeling for what we might be able to recover."
That made it easier for the solution phase of the project (fracture treatment) to receive management approval, even though a success and payout cost more money - and on that basis, the operator feels the investment was worthwhile.
Schlumberger said the project was rewarding for both parties. One of the two wells was returned to production, and the entire project paid out in 3 months. Field production levels also increased twofold, the contractor said. Water production remains nominal, and additional wellbores will be evaluated for stimulation treatments.
Furthermore, the operation marked one of the earliest uses of ScaleProp. And the project involved a lift-log procedure, whereby memory production logging equipment was deployed on coiled tubing with nitrogen on a live well and data obtained before water production killed the relevant well. A probabilistic model also was used to quantify the risks of the operation and identify the likelihood of success. This in turn was used to devise a commercial model for the data acquisition program that was commercially beneficial to Marathon and Schlumberger. This was the classic "risk- reward" element that made the work worthwhile for both parties.
Both parties also carried out their own engineering analyses, allowing further discussion and resolution of discrepancies.
And finally, by the time the intervention work had been done, a record tonnage
of proppant was put into the Brae formation.

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