Solutions to Complex Well-Testing Challenges Aid Offshore Black Sea Gasfield Development
Authors: Carpenter Chris 
Published: May 2024

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215123, “Frontiering Ultradeep Water Gas Field Development, Offshore Black Sea, Turkey: Solutions to Complex Well-Testing Challenges and Proving Production Potential,” by Coşan Ayan, SPE, Suat Aktepe, and Koscal Cig, Turkish Petroleum, et al. The paper has not been peer reviewed.

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Increasing demand for reliable energy resources has led to an increased exploration activity for untapped hydrocarbon resources in deep water. The recently discovered, fast-tracked Sakarya offshore natural gasfield development is a prime example. This paper describes dynamic reservoir characterization considerations, challenges, and engineering solutions to derisk field-development decisions, confirmed by a well-testing campaign in a complex setting with no tolerance for failure.

Sakarya Field
The Sakarya field is approximately 170 km north of the Turkish coast in the Black Sea at 2117 m (Fig. 1). The natural gas field was discovered in August 2020 and is estimated to have potential natural gas reserves of 11 Tcf of lean gas, making it the largest gas reserve discovered in the Turkish Exclusive Economic Zone as well as the Black Sea.
In October 2020, a second discovery was made in the lower sections of Tuna 1, which increased the potential recoverable reserve estimate to 14.3 Tcf of lean gas. The discovery was found at the deeper part of the well, where an additional 30 m of gas pay was encountered in the sandstone reservoir of the Late Miocene. Further, the drilling of the exploratory well Amasra 1, 40 km north of the Sakarya field, led to the discovery of 4.7 Tcf of gas in June 2021, and increased the potential recoverable cumulative natural gas reserves to 19 Tcf.
The first gas production from the Sakarya gas field began in 2023 into the Turkish grid from the completed wells of the first phase of the project. To accelerate the time to first gas production, it was deemed necessary to flow-test the reservoirs to acquire critical reservoir information, assess production potential and completions efficiency, and reduce the number of wells. This was achieved by drilling and testing several appraisal wells with multiple target intervals that will be used later as producers.

Well-Completion Strategy Affecting Well-Test Program
Formation-failure studies and wireline formation testing data have shown that these weak reservoirs are prone to sand production. As a result, downhole sand-exclusion completions are necessary. Gas permeabilities are good, with core-measured air permeabilities in the range of 1–1000 md. The reservoir pressure varies from 4,200 to 5,800 psi, depending on depth. Reservoir temperatures are relatively low, in the range of 25–60°C.
Lower Completion Installation Sequences.
After drilling, the main section was completed with 9⅞-in. 62.8-lbm/ft production casing. The selected interval from openhole logs and formation test results was perforated and overbalanced by individual runs of a tubing-conveyed perforation (TCP) system. On the second run, sump packers with direct wrap screens across the interval were installed and gravel was pumped. After the lower completion was in place and the drillstem test (DST) had been conducted, another part of the lower completion across the upper interval was installed and flow-tested. After completing all DST well tests, the well was suspended with the lower completion system in place, ready for installation of the upper completion with intelligent flow-control valves and permanent gauges.