GENERAL INTEREST Quick Takes
WoodMac: Oil, gas exploration spending to average $22 billion/yr through 2027
Oil and gas exploration expenditures (excluding appraisal) will rebound from historic lows, reaching an average of $22 billion annually in real terms over the next 5 years, according to a Wood Mackenzie report.
Tailwinds from appealing exploration economics, the need for energy security, and the emergence of new frontiers will incentivize oil and gas companies, predominantly National Oil Companies and Majors, to increase exploration spending through 2027, the report said.
“Explorers will become bolder in the coming years,” said Julie Wilson, director of global exploration research at Wood Mackenzie. “While this rebound might surprise some, it must be seen in context. exploration went through a boom during 2006-2014 and spend peaked at $79 billion (in 2023 terms). But in the prior 6 years, the average was $27 billion per year in 2023 terms. While spending will increase, it won’t return to anywhere close to past highs and there will likely be a ceiling on the increase. There is a lack of high-quality prospects that would satisfy today’s economic and ESG metrics and a continued focus on capital discipline will keep a lid on overspending.”
The growth will begin in 2023, with spending projected to increase 6.8% over 2022 totals (in real terms). A major driver for this increased activity is the robust business case. According to Wood Mackenzie, full-cycle returns from exploration have been consistently above 10% since 2018 and exceeded 20% in 2022.
“These positive results have increased confidence in exploration,” said Wilson. “Improved results are down to many factors. Portfolio high-grading coupled with greater discipline in spending and prospect choice mean only the best prospects are drilled and waste is minimized. Efficiency gains also serve to enhance the returns from both development and exploration.”
In the long term, deepwater and ultra-deepwater will provide the most growth opportunities for exploration. The Atlantic Margin of Africa and the Eastern Mediterranean regions will experience the greatest growth and there will also be spending in some unspecified new frontiers.
“There are areas where leads and prospects are being worked up with recent seismic data, for example Uruguay, southern Argentina and deepwater Malaysia,” added Wilson. “Future spending in ‘success case’ areas is additional exploration following success, whether that’s in a frontier like Namibia or Greece, or a more established province like Egypt’s Nile Delta.”
SilverBow to acquire South Texas Eagle Ford assets from Chesapeake
SilverBow Resources Inc. has agreed to acquire oil and gas assets in condensate-rich portion of the Eagle Ford shale play in South Texas from Chesapeake Energy Corp. for $700 million.
With the acquisition, SilverBow’s eighth over the past 2 years, the operator adds about 42,000 net acres (100% operated) in Dimmit and Webb counties across the liquids-heavy window of South Texas, along with related property, plant and equipment. Second-quarter 2023 average net daily production from the properties was about 29,000 boe/d (60% oil/NGLs). The acquisition increases SilverBow’s expected fourth-quarter 2023 net production to 87,000-99,000 boe/d (50% oil/NGLs).
Included are 300 additional high-confidence drilling locations across the Austin Chalk and Eagle Ford formations which immediately compete for capital, SilverBow said in its release Aug. 14.
For Chesapeake, the deal completes its exit from the Eagle Ford shale in South Texas, bringing total proceeds from multiple sales to more than $3.5 billion as it focuses its capital on its Marcellus and Haynesville positions.
SilverBow has also agreed to pay Chesapeake an additional contingent payment of $25 million should oil prices average $75-80/bbl WTI NYMEX or $50 million should WTI NYMEX prices average above $80 during the year following the deal’s close, which is currently expected by yearend, subject to certain regulatory approvals and consents.
Devon, WaterBridge NDB form Delaware basin produced water partnership
Devon Energy Corp. subsidiary WPX Energy Permian LLC has formed a partnership with WaterBridge NDB LLC, a portfolio company of private equity firm Five Point Energy LLC.
The new partnership—NDB Midstream LLC—is developing a large-scale water transportation, handling, and recycling system in the Stateline region, in Loving County, Texas, and Lea and Eddy counties in New Mexico, primarily on land owned by Five Point’s land management platform, DBR Land LLC, WaterBridge NDB said in a release Aug. 7.
Devon has committed to NDB Midstream all of its produced water within an area of mutual interest, including an initial dedication of 52,000 acres, and contributed to NDB Midstream 18 SWDs with 375,000 b/d of permitted capacity and 210 miles of produced water pipelines for gathering, transportation, disposal, and reuse.
Devon received a 30% equity interest in NDB Midstream as well as a commitment by Five Point to fund a portion of the initial build of the system expansion.
Devon holds 400,000 net acres in the Delaware basin, in what it calls its ‘franchise’ asset. In the second quarter, the company reached an all-time oil production record of 323,000 b/d. Of that, about 65% is attributed to Delaware basin acreage where an additional 34 wells were placed online in the quarter to reach a total of 76 wells online.
Also in the quarter, the successful Mule appraisal, an 11-well project in the Delaware basin, derisks about 100 locations in the Cotton Draw area, the company said.
The company expects to spend about 60% of its estimated 2023 total capital budget of $3.6-3.8 billion on Delaware basin assets.
Exploration & Development Quick Takes
Mellitah Oil & Gas lets offshore Libyan contract to Saipem
Mellitah Oil & Gas BV Libyan Branch, a consortium formed by National Oil Corp. of Libya and Eni North Africa, let a contract to Saipem for development of the Bouri Gas Utilization Project (BGUP) offshore Libya. The contract is worth about $1 billion.
Saipem will revamp the platforms and infrastructure of Bouri gas field in water depths of 145-183 m. The contract comprises engineering, procurement, construction, installation, and commissioning of an about 5,000-ton gas recovery module onto the existing DP4 offshore platform, together with laying 28 km of pipelines connecting DP3, DP4, and Sabratha platforms.
DNO Norge, OKEA agree to Brasse fast-track development concept
DNO Norge AS will transfer operatorship of the Brasse discovery in production license (PL) 740 to OKEA ASA and partners will investigate a tieback to nearby Brage field offshore Norway. A final investment decision is expected early next year.
The North Sea project was restarted in early 2023 with a review of a simplified tieback to the Brage platform 13 km north of Brasse. This review has led to approval of a concept selection (DG2) involving a much-reduced topside modification scope on Brage compared to previous considerations of a linkup with a host platform.
Well design has also been simplified to a two-well development targeting recovery of up to 30 MMboe from Brasse (estimated two-thirds oil and one-third natural gas and NGL), with a potential start-up as early as 2026.
In December 2022, OKEA and DNO ASA entered into an agreement for OKEA to become 50% owner of Brasse (OGJ Online, Dec. 29, 2022). Operatorship of Brasse will be transferred to OKEA from DNO on Sept. 1.
OKEA took over as Brage operator last fall and the main commercial terms for the tie-in have been agreed with the Brage joint venture, in which DNO holds a 14.2567% stake (OGJ Online, May 23, 2022).
OKEA also entered into an SPA with M Vest Energy AS (M Vest) to sell 4.4424% working interest in Brasse to further align ownership in the two licenses. The SPA is subject to customary government approvals.
IPR discovers hydrocarbons in Alamein-Yidma
IPR Energy Group (IPR) discovered hydrocarbons in the Alamein 48-K well in the Alamein-Yidma concession in Egypt’s western desert.
The well was drilled to a depth of 8,960 ft utilizing the IPR-1 750 HP Drilling Rig, while testing and completion was carried out with the IPR-2 350 HP Workover Unit. The well encountered 27 ft of net pay in the Lower Kharita reservoir, with an average production rate of 3,300 bo/d at 36°API with less than 1% basic sediment and water (BS&W) on a ½-in. choke. Total drilling and testing cost was $1.55 million.
The well will be completed with an electric submersible pump (ESP) and immediately put onstream through existing Alamein-Yidma infrastructure.
IPR holds 100% working interest in the concession.
Drilling & Production Quick Takes
Pioneer Natural Resources lifts full-year production guidance by about 3%
Pioneer Natural Resources Co. raised its 2023 oil production guidance after second-quarter oil-equivalent output topped forecasts and was up 11% from the same period last year.
Helped by operating costs that were 20% lower than in the spring of 2022, Pioneer also reported second-quarter profits of $1.1 billion on revenues of $4.6 billion. A year ago, those numbers were $2.4 billion and $6.9 billion, respectively. The operator averaged 711,000 boe/d during the 3 months ended June 30, beating the midpoint of their guidance from late April by about 3%. Oil production averaged 369,000 b/d versus a forecast midpoint of 364,500 b/d.
The company has lowered full-year spending plans on drilling, completions, and infrastructure in the Permian basin to $4.4-4.6 billion, the midpoint of which is $125 million lower than the previous outlook. The company plans to operate an average of 23-25 rigs, one fewer than previous guidance, and is looking to place 490-520 wells on production this year versus 500-530. Those numbers aren’t likely to grow much next year.
“We’ve had significant growth in productivity in 2023,” president Rich Dealy said on an earnings call. “That should make 2024 very capital-efficient. [It] probably means that we’re at the lower end of [adding] 1-2 rigs or maybe even potentially flat.”
Revised guidance for full-year 2023 now stands at 364,000-374,000 b/d, with total oil equivalent production expected to be 697,000-717,000 boe/d, up a little more than 3% from prior forecasts. The company averaged 662,000 boe/d in fourth-quarter 2022 and 680,000 boe/d in first-quarter 2023.
Hess using all-electric rigs in the Bakken
Hess Corp. is using four Nabors all-electric drilling rigs in the Bakken.
Nabors converted all of its Hess drilling rigs in the Bakken by installing its Canrig PowerTAP highline power transformer module to obtain power directly from the utility grid. Backup onsite generators ensure power goes uninterrupted should an outage occur.
Over the next 5 years, Hess expects that this fully electric fleet will reduce greenhouse gas emissions from its Bakken drilling operations by about 50% and energy costs by about 70%.
The project was piloted in 2022 and rig reliability increased by providing a secondary power source. Hess expects that electrification of its rigs and access to highline power will also reduce downtime.
PowerTAP enables highline power utilization on any AC drilling rig where grid power is accessible, regardless of rig manufacturer. It is skid-mounted and installed anywhere compatible utility electrical power is available using a standalone conductor cable reel. Field results from more than 20 PowerTAP modules deployed in the Lower 48 on Nabors and non-Nabors rigs indicate an initial average CO2e savings per rig of 20 tonnes/day.
In first-quarter 2023, Hess’s net production from the Bakken was 163,000 boe/d compared with 152,000 boe/d in the prior-year quarter, primarily due to higher NGL volumes received under percentage of proceeds contracts and increased drilling and completion activity.
bp lets contract for work offshore Egypt
bp has let a contract to drilling waste management specialist TWMA for large-scale oil and gas projects in Egypt.
TWMA will use its RotoMill drill cuttings processing technology to process all drilling waste generated from bp’s West Nile Delta (WND) and East Nile Delta (END) exploration and development projects in the Mediterranean Sea, the service provider said in a release Aug. 14.
WND is a multi-stage project which encompasses five fields in the North Alexandria and West Mediterranean Deepwater offshore concession blocks. END is in the North Damietta Offshore concession. bp has an 82.75% operating stake in WND and 100% equity in END.
RotoMill uses thermal desorption to separate drill cuttings and associated materials into oil, water, and solids for recycling and reuse. The recovered base oil can be reused in the drilling mud system.
Work will start in October 2023 and is expected to last up to 5 years. The contract is worth $15 million.
PROCESSING Quick Takes
ADNOC Gas lets contract to expand gas processing capacity, infrastructure
ADNOC Gas PLC has let a contract to a consortium of National Petroleum Construction Co. PJSC (NPCC) and Técnicas Reunidas SA for a project to expand gas processing infrastructure at the operator’s existing onshore installations in southwestern UAE’s Abu Dhabi Emirate.
As part of the $3.6-billion contract, the consortium will provide engineering procurement, construction, and commissioning (EPCC) services for new gas processing installations at ADNOC Gas’ multi-train gas processing complex at Habshan, Al Gharbia, that will enable optimized supply of feedstocks to ADNOC’s fully integrated, downstream Ruwais Industrial Complex (RIC) in Al Ruwais Industrial City, Al Dhafrah, ADNOC Gas said on Aug. 9.
Designed to increase ethane extraction capability at Habshan by 35-40% from current levels via construction of new gas processing units, the MERAM project also aims to unlock additional value from existing feedstock that will be delivered by a dedicated 120-km NGL pipeline to Ruwais, the operator said.
The Aug. 9 contract award NPCC and Técnicas Reunidas marks the start of the MERAM project’s formal execution phase previously scheduled to begin during second-quarter 2023.
ADNOC Gas said the MERAM project—on which the company reached final investment decision during first-quarter 2023—is scheduled for commissioning during third-quarter 2025.
The MERAM project is one of several by ADNOC Gas included under ADNOC’s integrated gas masterplan, which intends to link every part of the UAE’s gas-value chain to ensure sustainable and economic gas supplies to meet domestic and international demand.
Alongside processing infrastructure, the gas masterplan also entails new approaches and technologies to boost gas recovery from existing fields, as well as develop untapped resources, ADNOC Gas said.
In addition to MERAM, ADNOC Gas’ $14-billion, 5-year strategic and growth project portfolio for 2023-27 includes an expansion of its sales gas pipeline network by more than 500 km to beyond 3,500 km to better connect northern portions of the UAE (ESTIDAMA), as well as construction of a new gas processing installation that will add about 1.9 bcfd processing capacity to the company’s processing operations by 2028 at the earliest.
Petrobras weighs plan to restart fertilizer plant
Petróleo Brasileiro SA (Petrobras) is in the final phase of completing studies designed to evaluate the potential restart of subsidiary Araucária Nitrogenados SA’s (ANSA) mothballed fertilizer plant near the 208,000-b/d Refinaria Presidente Getulio Vargas (REPAR) refinery in Araucária, Paraná, in southern Brazil.
Following completion of technical and economic feasibility studies for the ANSA restart plan, Petrobras will submit results to its executive board and board of directors for the project’s approval, the operator said on Aug. 14.
Petrobras undertook studies to investigate potentially restarting the plant given the fertilizer sector’s strategic importance to both the company and Brazil, according to Jean Paul Prates, Petrobras’ chief executive officer.
While the global fertilizer market has recently faced many challenges, the plant’s proposed restart would enable Brazil—a major producer of agricultural commodities—to reduce its current dependence on imports of fertilizers from abroad, as well as generate employment opportunities for the regional economy lost since the plant’s idling in early 2020, according to Prates.
The planned restart, however, also would capitalize on Petrobras’ renewed focus on maximizing value of its existing operations showing economic viability, which—under the company’s 2023-27 strategic plan revealed in December 2022—includes ongoing investment in the REPAR refinery following the site’s delayed sale under Petrobras’ broader downstream divestment plan.
“Petrobras is interested in investing in the reactivation of ANSA because of [the plant’s] synergy with REPAR,” Prates said.
Equipped to produce about 1,900 tonnes/day of urea and 1,300 tonnes/day of ammonia for production of agricultural fertilizers, ANSA’s plant would receive its feedstock of asphalt residue from REPAR, the company said.
If approved for restart, ANSA’s fertilizer plant could resume operation as early as first-half 2024.
Petrobras’ decision to idle ANSA in early 2020 in part stemmed from the fact that the asphalt residue required to feed the plant—Brazil’s only based on such a feedstock—was, at the time, more expensive than its final products of ammonia and urea, the company said in a Jan. 14, 2020, release.
TRANSPORTATION Quick Takes
Plains adds Permian basin gathering interests
Plains All American has added to its Permian basin crude oil gathering asset portfolio.
A subsidiary of Plains Oryx Permian Basin LLC—a joint venture of Plains All American (PAA) and Oryx Midstream Services Permian Basin LLC (Oryx)—closed a deal July 28 to acquire Diamondback Energy’s 43% interest in OMOG JV LLC for about $225 million ($145 million net to
PAA’s interest).
According to regulatory filings, the OMOG crude oil gathering and transportation system includes about 400 miles of crude oil gathering and regional transportation pipelines and some 350,000 bbl of crude oil storage in Midland, Martin, Andrews and Ector Counties in Texas.
Acquisition of the remaining 43% interest in the Northern Midland basin gathering system further aligns the Plains Permian joint venture with Diamondback in the core of the Midland basin, PAA noted in its earnings call.
Commonwealth LNG completes deal for liquefaction plant development funding
Commonwealth LNG LLC partnered with Kimmeridge Energy Management Co. LLC to advance development of its 9.3-million tonne/year (tpy) liquefaction plant in Cameron Parish, La.
Investment capital provided by private funds managed by the alternative asset management firm completes the development funding required for Commonwealth LNG to reach final investment decision (FID) on the plant, Commonwealth LNG said in a release Aug. 14.
Commonwealth LNG and Kimmeridge have also agreed in principle on terms for a 20-year, 2 million tpy LNG offtake commitment along with the associated gas supply.
The agreement also includes key terms for Kimmeridge’s participation to provide additional equity to support plant construction.
“The recent LNG marketing progress, the completion of FEED, and the conclusion of the EPC contract with Technip Energies ensures Commonwealth commences delivering LNG to our customers in early 2027,” said Commonwealth LNG president and chief executive officer Farhad Ahrabi.
In November 2022, Commonwealth LNG received US Federal Energy Regulatory Commission approval for the liquefaction plant (OGJ Online, Nov. 18, 2022).
TSA updates pipeline cybersecurity directive
The US Transportation Security Administration (TSA) has updated its security directive regarding oil and natural gas pipeline cybersecurity.
Updates to the security directive require oil and natural gas pipeline owners and operators to:
- Annually submit an updated Cybersecurity Assessment Plan to TSA for review and approval.
- Annually report results from previous year’s assessment, with a schedule for assessing and auditing specific cybersecurity measures for effectiveness. TSA requires 100% of an owner-operator’s security measures be assessed every 3 years.
- Test at least two Cybersecurity Incident Response Plan (CIRP) objectives and include individuals serving in positions identified in the CIRP in required annual exercises.
The reissued security directive was developed with input from industry and other federal agencies, including the Cybersecurity and Infrastructure Security Agency (CISA) and the Department of Transportation, Remaining in place are previously established requirements to report significant cybersecurity incidents to CISA, identify a cybersecurity point of contact, and conduct a cybersecurity vulnerability assessment (Security Directive Pipeline 2021-01C).
TSA originally issued the directive following a May 2021 ransomware attack that led to the 6-day shutdown of Colonial Pipeline Co.’s 5,500-mile refined products pipeline. Colonial carries 45% of the US East Coast’s gasoline, diesel, and jet fuel.