TAG Oil finds oil-bearing sandstones in Taranaki Basin, New Zealand

TAG Oil Ltd. has made an oil find in the Taranki Basin, North Island New Zealand. The company reports that the Cheal-B4ST well is a multi-zone light oil discovery. Cheal-B4ST was drilled to a total depth of 5,937 feet, encountering 55.7 feet of net oil-bearing sandstones within the Urenui and Mt. Messenger Formations. Electric logs indicate four separate zones are likely to be oil-charged with excellent porosity and permeability.

TAG reports that two of the four zones intersected are oil-bearing zones never before encountered in wells within PMP 38156, further demonstrating that the entire 7500-acre PMP 38156 area is oil-prone, with multiple shallow horizons prospective for discovery.

TAG will now complete the Cheal-B4ST well in preparation for flow testing in coming weeks.

The Cheal-B4ST well is the first in a series of high-impact exploration wells to be drilled in TAG Oil's onshore Taranaki Basin acreage.

In its second major deal since the Macondo Gulf of Mexico spill, oil giant BP has agreed to acquire upstream assets offshore India from privately-held Reliance Industries Ltd. for US$7.2 billion.

Completion of the transaction, subject to Indian regulatory approvals and other conditions, would result in BP taking a 30% stake in 23 oil and gas production sharing contracts covering 270,000 square kilometers that Reliance operates in India, including the producing KG D6 block. This block contains the D-1 and D-3 gas fields, which contain over 13 trillion cubic feet (tcf) of proved and probable reserves.

According to a Feb. 21 report by Jefferies & Co. Inc., these particular fields have been producing at a combined rate of 1.8 billion cubic feet per day (bcf/d) in recent months, although production rates have fallen as reservoir complexity has restricted well deliverability. The fields were originally planned to peak at 2.8 bcf/d, and Jefferies speculates that restoring field output may be one reason Reliance agreed to partner with BP.

A 50/50 joint venture would also be created to source and market gas in India as well as to accelerate the creation of infrastructure to handle the gas.

BP will pay Reliance an aggregate consideration of US$7.2 billion, and completion adjustments, for the interests in the production sharing contracts. Jefferies & Co. translates the unit price for the proved and probable reserves near US$9.3/boe. The company is expected to pay the US$7.2 billion sequentially over 2011 out of cash reserves and payments of up to US$1.8 billion could be shelled out by BP depending on further exploration success.

Reliance will continue to serve as operator of the blocks that currently produce nearly over 30% of India's total consumption and over 40% of India's total production.

"By allying ourselves with Reliance, we will access the most prolific gas basin in India and secure a place in the fast growing Indian gas markets, creating a genuinely distinctive BP position," said Robert Dudley, BP Group chief executive.

Growth is one factor keeping Jefferies neutral on BP. Its analysts are concerned about BP's relative lack of medium-term organic growth compared to its peers. "This deal, although reasonably priced, does not, in our opinion, offer enough upside to compensate for the expected lack of growth from its key Gulf of Mexico assets."

Mogul Energy International Inc. announced an offsetting discovery at the La Ward NE Field area in Jackson County, Texas. Mogul successfully completed the drilling of the Stafford Well #1 on March 6th and has been running tests over the weekend. The well, located just approximately 10 miles south of Ganado, was drilled to a total depth of 7,400 feet.

Initial open-hole logging indicates multiple productive zones from the Frio formation with both oil and gas shows. The deepest prospective oil zone shows a structural sand 10 feet higher to an offsetting productive well with a sand thickness of 5 ½ feet with a 33% porosity and 20% water saturation. The cumulative thickness of these productive sands was greater than originally expected. Additional tests and analysis of the several other productive zones will continue while the casing is installed, cemented and surface equipment are put into place. Mogul will evaluate the results of this well for potential offsetting locations in the near future.

President and CEO Tim Turner said, "Our discovery near the La Ward NE Field is an important development for our Company. Current plans consist of completing the well for both oil and gas production with connections to nearby infrastructure, and we anticipate the first production from this well in a matter of weeks. We look forward to continuing this success with our other South Texas prospects currently being developed."

Mogul operates the Stafford well discovery with a 15% working interest. Other interest owners in the discovery are Fossil Oil Co. LLC with 33.33%, C. H. Squyres Family LLC with 33.33%, Aura Oil Holdings Ltd. with 8.33%, Global Oil & Gas Resources Inc. with 5%, Dolomiti Partners LLC with 2.5% and Indian Lane Assoc. LLC with 2.50%.

Maersk Oil announced today that the appraisal well 22/25a-10z in the high pressure high temperature Culzean discovery has confirmed the presence of a significant hydrocarbon accumulation.

The Maersk Oil operated well was drilled in the UK sector of the Central North Sea approximately 145 kilometers East of Aberdeen to verify the extension of the original Culzean discovery well (22/25a -9z), announced in 2008.

Gas and condensate has been confirmed at an average depth of approximately 4.5 km, within the target reservoirs of Triassic and Jurassic age. The well has been tested in two intervals and delivered a rig constrained rate of nearly 40 million cubic feet of gas in addition to 900 barrels of condensate per day in each interval.

Maersk Oil and its partners have agreed to a further appraisal program which includes a sidetrack well down flank to the east of the appraisal well to assess the full extent of the field. The results of this sidetrack well are expected in summer 2011 after which a further appraisal well will be drilled.

Maersk Oil as operator holds a 49.99% interest in Culzean, with partners JX Nippon UK (17.06%) Eni UK (16.95%) and BP (16%).

The find comes less than a month after Maersk Oil Brasil and partner OGX reported finding oil in the ongoing Carambola B exploration well in the Campos Basin off the coast of Rio de Janeiro. Maersk Oil serves as the operator with a 50% share of the block where a preliminary estimate of up to 17 meters of net pay hydrocarbons were found. Coring, pressure measurements and hydrocarbon sampling were performed. Further work will assess productivity.

The size of European unconventional commercial gas reserves rival that of North America, according to a new study by IHS Cambridge Energy Research Associates (IHS CERA). The study, Breaking with Convention: Prospects for European Unconventional Gas estimates Europe's total unconventional gas in place could be 6,115 trillion cubic feet (tcf). Based on the systemic analysis of the key unconventional gas plays in Europe (both shale gas and coal bed methane) and drawing on IHS proprietary databases, the study explores the extent to which the sizeable potential of unconventional gas is likely to be realized and what it means for European gas markets.

"The technological revolution in unconventional gas has been the single most important energy innovation so far this century," said IHS CERA chairman Daniel Yergin. "Its tremendous potential has already transformed North America's energy landscape and may now transform the global gas industry."

Unconventional gas in Europe is likely to make significant contributions to supply in the next 10 to 15 years, the report says. IHS CERA estimates production levels ranging from a minimum of 60 billion cubic meters (bcm)—less than half of current shale gas production in North America—to 200 bcm around 2025.

Among the key challenges that will determine the ultimate productivity in Europe is a regulatory environment that is currently ill-suited to unconventional gas, the report says.

"Regulations designed for traditional exploration and production have not been adapted to reflect the character of unconventional gas," said Jonathan Parry, IHS CERA global gas director. "But there are significant challenges ahead, including uncertainties over length of tenure, permitting regimes and norms and water management, among others."

The delivery price of unconventional gas is also expected to be higher than the current prices of Europe's present import sources. However, IHS CERA's oil price assumptions place the cost of unconventional gas on par with the long-term average price of contract gas, given the expectation that long-term contracts incorporating some linkage to the price of oil will remain the norm for some considerable time.

"Unlike in the United States—where the revolution in unconventional gas production has made the market nearly self-sufficient—unconventional volumes of gas in Europe are likely to keep domestic supplies stable in the face of declining conventional production," said Jan Roelofsen, IHS global senior product manager.

The impacts of the stabilization of domestic supply, though not as revolutionary, could be substantia. A stabilized domestic supply could alleviate current fears over security of supply and increase the level of comfort with higher levels of reliance on gas, including imports. European policymakers could then be faced with an important strategic choice between a domestic secure and relatively-clean unconventional gas and more costly zero-emission alternatives.

"There is no question that substantial production of unconventional gas in Europe would have a major impact on the dynamics of Europe and Asian gas markets," said Shankari Srinivasan, IHS CERA managing director Europe, global gas.

On March 18, the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) provided the final approval necessary for Petrobras America Inc. to begin oil and natural gas production at its Cascade-Chinook project using a Floating Production Storage Offloading (FPSO) facility. This will be the first time this technology is used in the US Gulf of Mexico.

BOEMRE approved the project's production safety system permit and supplemental deepwater operating plan (DWOP), to ensure that stringent safety regulations were met. The FPSO has a production capacity of 80,000 barrels of oil per day and 16 million cubic feet of natural gas per day. With the completion of this final regulatory step, production from this facility is expected to begin in the near future.

The Cascade-Chinook oil and natural gas project, located in the Walker Ridge area of the Gulf, about 165 miles offshore Louisiana in 8,200 feet of water, will use an FPSO, the BW Pioneer, which is a floating facility that has the capability to process oil and natural gas, store the crude oil in tanks located in the facility's hull, and offload the crude to shuttle tankers for transportation to shore. Natural gas processed by the facility will be transported to shore by pipeline. Petrobras' FPSO will be equipped with a disconnectable turret-buoy. In the event of a hurricane or tropical storm, the facility is designed to disconnect from the turret-buoy and move off location until the storm has passed.

"These regulatory approvals pave the way for safe, new production of oil and gas resources in the Gulf of Mexico," said Michael R. Bromwich, BOEMRE director. "They reflect enormous and sustained effort by both BOEMRE and Petrobras personnel and represent the commitment shared by government and industry to the safe production of our country's offshore energy resources."

The production safety system permit approved March 18 includes details of the production process that will be utilized, with specific description of the safety systems associated with the flow of oil and gas from the subsea wells to the process equipment onboard the FPSO. The approval process included an engineering analysis of the safety systems, as well as multiple pre-production inspections of the actual FPSO facility by BOEMRE personnel. The requirements for approval of a production safety system are covered in the Code of Federal Regulations, 30CFR250.800 – 808.

A DWOP includes the specific details and capabilities of the FPSO facility and associated new technologies. The initial DWOP for this project was approved in August 2009. Subsequently, Petrobras submitted a supplemental DWOP with information regarding adjustments to the mooring system, including alternative methods of monitoring the tensions of the mooring lines. BOEMRE engineering staff worked with Petrobras to ensure that safety requirements were met. The requirements for approval of a DWOP are covered in the Code of Federal Regulations, 30CFR250.286 – 295.

In preparation for this first use of an FPSO in the Gulf of Mexico, the then-Minerals Management Service and the US Coast Guard worked to identify and clarify responsibilities in a Memorandum of Agreement (MOA) in February 2008. The MOA assigned responsibilities to each agency for regulating or approving specific systems associated with the floating facility. BOEMRE regulates oil and natural gas activities such as exploration, drilling, well completion, development, production, pipeline transportation, storage, well servicing and workover activities, while the US Coast Guard regulates offshore facilities, mobile offshore drilling units, and vessels engaged in oil and gas activities such as tank vessels and offshore supply vessels.

Rockhopper Exploration has discovered a significant oil column in an appraisal well in the North Falkland Islands Basin in the South Atlantic Ocean. According to the UK-based company, Well 14/10-4 uncovered 108 feet (33 meters) of net pay in good quality reservoir with 20% average porosity. The well was drilled to a total depth of 9,190 feet (2,801 meters), finding the oil-water contact level at 8,127 feet (2,477 meters).

The well was spudded last month and lies just over one mile away from 14/10-2 discovery well. It is designed to investigate just how deep the reservoir is.

The top of the Sea Lion reservoir sands were encountered 216 feet (66 meters) downdip from the 14/10-2 discovery well. A total reservoir package of 351 feet (107 meters), comprising four main sands was encountered with a net to gross of 76%.

Ninety-eight feet (30 meters) of net pay has been encountered in the upper of the four sands, representing the main Sea Lion southern fan. The gross oil column now proven in the main Sea Lion southern fan is 341 feet (104 meters).

Rockhopper says the results of this first appraisal well will significantly increase the contingent P90 volume for this oil discovery. The P50 and P10 contingent volumes will be defined as the appraisal program progresses through the remainder of 2011.

The well will be plugged and abandoned as planned and subsequently the company will begin development planning for the Sea Lion discovery.

Rockhopper CEO Samuel Moody commented, "Following this positive result we believe Sea Lion is highly likely to prove commercially viable. The well has confirmed our ability to identify good reservoir units on the seismic in our acreage with the sands coming in very close to prognosis. We can now continue to appraise the Sea Lion discovery and to explore additional prospectivity within our acreage with added confidence."

Secretary of the Interior Ken Salazar and Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) Director Michael R. Bromwich announced that the bureau has approved an Exploration Plan, submitted by Shell Offshore Inc., following the completion of a site-specific Environmental Assessment (SEA) for deepwater oil and gas exploration.

This is the first new deepwater exploration plan approved since the Deepwater Horizon explosion and resulting oil spill. An exploration plan describes all exploration activities planned by the operator for a specific lease or leases, including the timing of these activities, information concerning drilling vessels, the location of each planned well, and other relevant information that needs to meet important safety standards. Once a plan is approved, additional new applications for permits to drill can be issued.

"The successful completion of this environmental assessment, and the resulting approval of Shell's exploration plan, unmistakably demonstrates that oil and gas exploration can continue responsibly in deep water," said BOEMRE Director Bromwich. "Shell's submission has satisfied the heightened environmental standards that we are now applying and I am confident that other operators can satisfy the same standards."

The plan is a supplemental exploration plan that proposes activities that were not included in an original exploration plan for the same lease – located in Shell's Auger field – which was approved in 1985. This supplements the original plan by proposing to drill three exploratory wells in approximately 2,950 feet water depth, 130 miles offshore Louisiana.

BOEMRE prepared the SEA to examine Shell's proposed exploration activities in accordance with the National Environmental Policy Act (NEPA) and the implementation of departmental and bureau regulations.

The SEA included new scientific information that had not been previously available for consideration or analysis. Based on its review, BOEMRE found no evidence that the proposed action would significantly affect the quality of the human environment. Therefore, BOEMRE determined that an Environmental Impact Statement (EIS) was not required and issued a Finding of No Significant Impact (FONSI), which allowed the supplemental exploration plan to be approved.

Woodside advised that the Martin-1 well in permit WA-404-P has intersected approximately 100 meters of gross gas within the Triassic target.

The well reached a total depth of 4,778 meters. Wireline logging has confirmed the discovery through the recovery of gas samples to surface and establishment of a gas pressure gradient.

Martin-1 is located in Western Australia's Carnarvon Basin within 14 km of Woodside's existing gas discoveries at Martell-1, Noblige-1, Larsen-1, Larsen Deep-1 and Remy-1.

Woodside is the operator and 100% equity owner of WA-404-P.

With well EWS I - 38 located in West Siberia, Exillon Energy plc has found oil on the eastern part of the East EWS I field. Additionally, legacy exploration well EWS I - 1 on the southern part of the EWS I field has been successfully re-completed.

EWS I - 38 well, spud on March 2, encountered the Jurassic P reservoir at 1,858m which is 2m higher than previously thought. Results of wire line logging combined with oil shows and sample analysis whilst drilling, have confirmed the presence of at least 9m of net oil pay within the Jurassic. Testing will be completed mid-April.

The well was drilled directionally 1.1km to the north-east from the existing well pad. On completion of testing the well will be connected to existing production facilities.

Exploration well EWS I -1 is located on the southern part of the field. The well was originally drilled in 1971, but was suspended due to the absence of production infrastructure.

In March, after re-interpreting the well logs, the group saw that wire line logging indicates the presence of 7.2m of net oil pay within the Jurassic P reservoir, which represents more than a three fold increase from the previous estimate. The group perforated additional intervals and the well flowed water-free oil naturally to the surface with a flow rate of 530 bbl/day on a restricted 8 mm choke.

More Oil & Gas Financial Journal Current Issue Articles
More Oil & Gas Financial Journal Archives Issue Articles
View Oil and Gas Articles on PennEnergy.com