Continental Resources Inc. has completed two Woodford producers in the Scoop play at an increased density pilot project in the Anadarko Basin in Stephens County, Okla. IHS Markit reported #7-6-7XH Sympson, Section 6-2n-4w, was tested on a 40/64-in. choke flowing 603 Mcm (21.3 MMcf) of gas, 472 bbl of 61-degree-gravity condensate and 2.088 Mbbl of water per day. The 7,877-m (25,843- ft) venture was drilled to the south with a true vertical depth of 4,473 m (14,674 ft). It bottomed in Section 7-2n-4w and was acidized and fractured at 4,740 m to 7,824 m (15,550 ft to 25,668 ft). About 3 km (2 miles) to the south in Section 18-2n-4w, the #4-7H Sympson produced 467 Mcm (16.5 MMcf) of gas and 276 bbl of 57-degree-gravity condensate. It was drilled to 5,917 m (19,413 ft [or 16,085 ft true vertical]), and production is from an acidized and fractured zone at 4,908 m to 5,894.5 m (16,102 ft to 19,339 ft). Both ventures are deferred completions of wells first drilled by Continental in 2015.
Eni completed #2-Tecoalli, a well in Campeche Bay offshore Mexico. The well was drilled in 33 m (108 ft) of water and reached a final depth of 4,420 m (14,501 ft). It hit about 40 m (131 ft) of net oil pay in Orca with excellent quality sandstone reservoirs. The well was then deepened to the Cinco Presidentes exploratory target and encountered an additional 27 m (88.5 ft) of net oil pay. A production test will be executed, and the well will be temporarily abandoned. The find is in Area 1 between Tecoalli Field and Amoca Field. The discovery increases the in-place hydrocarbon estimate from 1.4 Bbbl to 2 Bbbl, of which about 90% is oil and the remaining is associated gas. Eni is working on a development plan, and first production is expected in 2019.
GeoPark drilled and tested appraisal well #4-Tigana Norte in the Llanos 34 Block in Colombia. The Tigana Field well was drilled to 3,575 m (11,730 ft) and had oil shows in Guadalupe and Mirador. A production test conducted with an electric submersible pump in Guadalupe flowed 1.9 Mbbl of 14.1-degree-gravity oil, with a 1.8% water cut. It was tested on a 34/64-in. choke, and the wellhead pressure was 178 psi. Bottomhole pressure recorders from the latest tests performed indicate a producing drawdown of about 30%. GeoPark is drilling #5-Tigana Norte 5 to a bottomhole location that is farther down-dip of the #4-Tigana Norte well to further delineate the northeastern boundaries of Tigana Field.
Petrel Energy has spudded exploration well #1-Cerro de Chaga as part of an exploration program in Uruguay’s Norte Basin. The Salto Basin venture will test a four-way dip closure in Devonian source rocks including Mangrullo Shale. The organic-rich Mangrullo Shale is similar in age to the Bakken Shale. According to the company, #1-Cerro Padilla was drilled to 845 m (2,772 ft) and hit 2 m (6.5 ft) of oil in a saturated sand zone at 793 m (2,601 ft).
A study conducted by FAR Ltd. for two Gambia blocks, A2 and A5, indicates a potential for 1.1 Bbbl of oil with an unrisked, recoverable net estimate of 926 MMbbl. Blocks A2 and A5 are within the emerging Mauritania-Senegal Guinea-Bissau Basin and are on-trend with the recent offshore Gambia discoveries by Cairn Energy. Two drillable prospects have been mapped at prospects Samo and Bambo. The Bambo prospect has been identified following recent mapping of the 3-D seismic and targets a separate reservoir objective on the same structural trend as the Samo prospect.
Eni and Chariot Oil & Gas have scheduled an exploration well in the Rabat Deep Offshore Block of Morocco. Eni plans to spud #1-Rabat Deep (RD- 1) well on the JP-1 Prospect in 2018. The JP-1 Prospect is a large, four-way dip closed structure of about 200 sq km (77 sq miles) in areal extent, with Jurassic carbonate primary reservoir objectives. An independent estimate of the gross mean prospective resource is 768 MMbbl of oil. According to Chariot, the Rabat Deep permits have an additional six leads in the same play that have the potential to be de-risked by #1-Rabat Deep.
A study commissioned by Europa Oil & Gas for offshore Ireland’s Slyne Basin indicates several significant potentially gas-bearing structures. The study is based on legacy 3-D seismic data and data recently released from exploration well #18/20-7 that was drilled in 2010 into Corrib North, a Triassic sandstone reservoir prospect on LO 16/20. According to the company, the prospective resources estimate is 39.6 Bcm (1.4 Tcf) of gas in place. Log data from the exploration well suggest the presence of gas at Corrib North, which is a separate anticline north of the Corrib gas field. Based on mapping, Europa believes the full gas column at Corrib North has the potential to be 170 m (558 ft) thick.
Logging results from a Selva Field directional test in northern Italy’s Po Valley indicate a gross gas pay zone of 53 m (174 ft). The venture, #1-Podere Maiar by Po Valley Energy, is in the Podere Galina Block in Bologna, Italy. The well was drilled to 1,330 m (4,363.5 ft) and was targeting Pliocene. Plans call for casing, perforating and installing downhole production equipment in early 2018.
A report by Netherland Sewell & Associates for Energean Oil & Gas indicates the combined net, unrisked prospective recoverable resources for two offshore Montenegro blocks contain 50.9 Bcm (1.8 Tcf) of gas and 144 MMbbl of liquids. Energean is the sole operator of the Adriatic Sea blocks 4218-30 and 4219-26, with 100% working interest. The blocks cover a surface area of 338 sq km (130.5 sq miles) in shallow waters.
Mubadala Petroleum announced results from an exploration well in the Gulf of Thailand at #6-Manora in the G1/48 concession. The operator reported that the well was drilled to a true vertical depth of 2,412 m (7,913 ft), and it was targeting the L fault block prospect. Interpretation of the LWD data indicates a 5.8-m (19-ft) oil column in the primary reservoir section at a depth of 2,229 m (7,313 ft). Based on these results, a sidetrack, #6ST-Manora, was drilled to test the M prospect. The sidetrack was drilled to 2,387 m (7,831 ft) and LWD data indicated 5.9 m (19 ft) of oil in three separate reservoir sandstones, each of which exhibited evidence of an oil-water contact.
Australia Worldwide Exploration announced results from fl ow testing at #4-Waitsia in the Waitsia gas fi eld in onshore Western Australia. The well fl owed gas at an instantaneous maximum rate of 2.54 MMcm/d (90 MMcf/d) and an average of 2.53 MMcm/d (89.6 MMcf/d) during testing on a 96/64-in. choke with a flowing well pressure of 2,395 psi from Kingia Sandstone. The well hit a 50-m (164-ft) zone between 3,370 m and 3,420 m (11,056 ft and 11,220 ft).