IHS Markit: Rising costs tighten Permian economics
Exploration and production firms that acquired Permian basin acreage in the land grab of 2016 are now faced with maintaining premium valuations while meeting high-growth expectations in a rising cost environment, according to research by IHS Markit.
Despite the Permian's continued economic attractiveness, rising service sector costs will raise per-well capital expenditure by more than 15% during 2017, said Imre Kugler, senior consultant at IHS Markit.
"The economics for the Permian are still impressive at a $41/bbl weighted average for a $55/bbl [West Texas Intermediate] price-projection, but costs are rising, mostly for service sector-related costs of drilling and completion, proppant, sand, and a tightening rig market as utilization rates increase," Kugler said. "While Permian and Anadarko basin plays remain in the money, so to speak, lofty acquisition values become more difficult to pay off when the plays require nearly $50/bbl WTI to produce a 10% internal rate of return."
Many firms are able to offset rising service-sector costs with increased productivity, particularly in the early life Permian plays, while more mature plays outside of the basin have reached a plateau with economics primarily altered by cost, Kugler explained. Outside the Permian, the lack of infrastructure bottlenecks will place less cost pressure on the Bakken, Wattenberg, and Eagle Ford regions.
"Oil-price stabilization is creating greater confidence, and pumper calendars are filling up quickly," said Thomas Jacob, research consultant at IHS Markit. "In the Permian in particular we see significant expansion in drilling and completion activity. As a result, we at IHS Markit estimate the play will increase its proppant consumption from 20% of the US market in 2014 to 37% of the market in 2017."
Jacob said an increase in the number of wells hydraulically fractured in 2017 and higher frac-sand-mass-per-well assumptions for fourth-quarter 2016 and beyond have led to a 62% increase in North American frac-sand demand in 2017. "This year, mine-gate sand prices are expected to increase by roughly 50%, and, in particular, fine-grade sand prices are increasing most significantly," he said. "The market share of fine-grade sand increased from 60% in 2014 to 80% in 2017."
Chisholm Energy startup enters Delaware basin
Chisholm Energy Holdings LLC, a Fort Worth startup backed by a $500-million line-of-equity from private equity firm Warburg Pincus LLC, has acquired acreage in Eddy and Lea counties of New Mexico from an undisclosed private seller.
Chisholm says "the asset includes a substantial amount of highly attractive undeveloped acreage with multiple targets in the Bone Spring and Wolfcamp formations." Terms of the deal were not disclosed.
Formed in May 2016 to target the northern Delaware basin, Chisholm plans "to pursue unconventional resource opportunities where it can leverage its horizontal drilling and completions expertise."
Chisholm's CEO is Mark Whitley, who served as an advisor to WP starting in 2014 and previously was senior vice-president of Range Resources Corp.'s Southwest division.
Hope dims again for Cypriot reunification
Prospects for the reunification of Cyprus, which improved last month with the resumption of negotiations between Greek and Turkish Cypriot leaders after a 54-day break, have dimmed again (OGJ Online, Apr. 12, 2017).
The standoff precludes settlement of a territorial dispute that thwarts consideration of a pipeline between deepwater gas discoveries in the Eastern Mediterranean and Turkey.
Offshore oil and gas work figures in the latest setback to efforts to end 43 years of partition of the island nation.
Since last month's agreement to schedule new talks by Greek Cypriot leader Nicos Anastasiades and Turkish Cypriot leader Mustafa Akinci, new conflict has flared over Cyprus's Exclusive Economic Zone (EEZ).
Turkey issued maritime notices about its plans for military drills and seismic surveys in the EEZ. And Turkish frigates have menaced seismic vessels working in disputed Block 6.
Anastasiades complained about the Turkish activity in a May 8 letter to United Nations Sec. Gen. Antonio Guterres in which he said Espen Barth Eide, the UN special envoy to Cyprus, shows bias in favor of Turkey. He said Eide should not make statements or issue warnings.
On May 11, Eide appealed to leaders of both sides to relax tension, saying, "We may be looking forward to rather dramatic times."
Muruk confirmed as Hides lookalike in PNG
The Oil Search Ltd.-operated Muruk-1/ST3 sidetrack appraisal well in the highlands of Papua New Guinea has confirmed a natural gas-rich zone found in the initial Muruk-1 discovery in permit PPL 402 last December.
The sidetrack, drilled just southwest of the discovery well, encountered gas saturation through the entire Toro sandstone reservoir section with no gas-water contact observed.
Oil Search said the Cretaceous reservoir has the same high quality as that of giant producing Hides gas field that lies 21 km to the southeast (see map, OGJ Online, Nov. 17, 2016).
Muruk-1/ST3 was drilled to a total depth of 4,130 m. The Toro was penetrated at 3,968 m.
Two cores were cut and a full suite of logging and pressure data tools was run. The information is now being evaluated ahead of a likely production test.
Oil Search added that there is little doubt the well has found a potentially substantial gas field. Its close proximity to Hides means it could be a welcome contributor in support of a proposed third train in the Papua New Guinea LNG project.
News of the successful appraisal came after the first sidetrack Muruk-1/ST2, drilled last month northeast of the discovery well, found the Toro reservoir to be tightly folded and contorted containing water only.
The sidetracks were drilled in an attempt to find the gas-water contact. So far the gas column appears to be 350 m thick. Predrill estimates suggested the structure has potential to hold 1-3 tcf of gas.
Further appraisal of the Muruk discovery is being considered for 2018.
Three other prospects in the northwest highlands are on trend with Muruk and these may also be included in future drilling programs depending on the results of the current drilling and additional seismic work.
Oil Search is operator with 37.5%. Other participants are ExxonMobil Corp. with 42.5% and Santos Ltd. with 20%.
Beach targets undeveloped Cooper basin oil reserves
A group led by Beach Energy Ltd. and including Cooper Energy Ltd., both of Adelaide, has started a five-well drilling campaign in South Australian production permit PPL 220, which contains Callawonga oil field on the Cooper basin's western flank.
The program is specifically targeting previously undeveloped reserves in the McKinlay Member sandstone that lies immediately above the Namur Sandstone, which is the main producing reservoir at the field.
Beach says that so far no oil-water contact has been encountered within the McKinlay reservoir. The drilling campaign will include both development and appraisal well locations with the potential to extend the known boundaries of Callawonga field.
The new wells will be numbered Callawonga 14-18, although the drilling sequence will be determined by the results of each individual well. Callawonga-14, spudded during the weekend, is at 198 m and is expected to take 6 days to reach its planned 1,410-m total depth.
The five-well program is scheduled for completion by mid-July and the combine is planning to connect the wells to the field production system during August-September.
Two Callawonga producers, Nos. 7 and 12, are already tapping parts of the McKinlay Member at a combined rate of 500 b/d of oil.
Operator Beach has 75% of the field. Cooper Energy holds the remaining interest.
Tullow finds net oil pay with Emekuya-1 well in Kenya
Tullow Oil PLC's Emekuya-1 well, drilled on Block 13T of northern Kenya, has found 75 m of net oil pay in two zones.
Emekuya-1 was drilled 2½ km north of the Etom-2 well and had the objective of drilling a fault block on the flank of the Greater Etom structure. The well was drilled by PR Marriott Drilling Ltd.'s Rig 46 to a total measured depth of 1,356 m and penetrated reservoir quality Miocene sandstone that correlate to those seen in the Etom-2 well (OGJ Online, Dec. 15, 2015).
Downhole pressure measurements and fluid samples suggest the main oil reservoir is on the same static pressure gradient as the Etom-2 well, which demonstrates that a major part of the Greater Etom structure is oil-filled. Tullow says the encountered reservoir sands also appear to be extensive, further derisking the northern play area and boding well for future exploration in the region.
"The Emekuya-1 exploratory appraisal well has made an important discovery in the northern part of the South Lokichar basin," explained Angus McCoss, Tullow exploration director. "This well has proven oil charge across a significant part of the Greater Etom structure and we are very encouraged by the quality and particularly the regional extent of the reservoir. We now look forward to the remainder of the Kenya exploration and appraisal campaign in support of the ongoing work to prepare this important asset for full-field development."
The rig will be moved to drill an updip appraisal well on the Greater Etom structure. Tullow operates Blocks 13T and 10BB with 50% interest. Partners are Africa Oil Corp. and Maersk Oil each with 25% interest.
Drilling & Production — Quick TakesBP begins gas production from West Nile Delta
BP PLC has started gas production from Taurus and Libra fields, the first two of five fields in the West Nile Delta development of Egypt.
The fields are currently producing more than 700 MMscfd of sales gas and 1,000 b/d of condensate. Following final approval in 2015, development of Taurus and Libra was fast-tracked by 8 months to enable delivery of an annual average of more than 600 MMscfd to Egypt's national gas grid, which first received gas from the project Mar. 24.
The Taurus and Libra project is a subsea greenfield development including nine wells-six in Taurus and three in Libra-and a 42-km tieback to the existing onshore processing facility where gas enters the Egyptian grid via a nearby export pipeline. Commissioning of all nine wells and ramp up to stable operations has been completed.
The West Nile Delta development, which encompasses the North Alexandria and West Mediterranean Deepwater offshore concession blocks, is being developed as two separate projects. When fully on stream in 2019, combined production from both projects is expected to reach nearly 1.5 billion bcfd, equivalent to about 30% of Egypt's current gas production. All gas produced will be fed into the national gas grid.
BP says the second West Nile Delta project, involving development of Giza, Fayoum, and Raven fields, also is ahead of schedule and under budget. The project will involve 12 wells and two deepwater long-distance subsea tiebacks to shore. Fluids will be processed through an onshore plant modified for Giza and Fayoum and integrated with a new adjacent onshore plant for Raven. Production from Giza, Fayoum, and Raven is expected to start in 2019.
BP is operator of the West Nile Delta project with 82.75% interest. DEA Deutsche Erdoel AG holds the remaining 17.25%.
Eni begins gas production from Jangkrik project
Eni SPA has started gas production from the Jangkrik development project in the deep waters offshore Indonesia. The project comprises Jangkrik and Jangkrik North East gas fields on the Muara Bakau block of the Kutei basin in the Makassar Strait.
Production from 10 deepwater subsea wells connected to the Jangkrik floating production unit (FPU) will gradually reach 450 MMscfd, or 83,000 boe/d. Once processed onboard the FPU, gas will flow via a 79-km pipeline to an onshore receiving facility and then through the East Kalimantan transportation system, finally reaching the Bontang gas liquefaction plant.
Production start-up comes less than 3½ years after project sanction. Gas volumes from Jangkrik will supply the Indonesian market as well as the LNG export market.
The Jangkrik FPU may also be used as a development hub for Eni's Merakes gas discovery, which Eni says could start production in the next 2 years.
Eni subsidiary Eni Muara Bakau BV is operator of the Muara Bakau production-sharing contract with 55% interest. Partners are Engie E&P subsidiary GDF SUEZ Exploration Indonesia BV with 33.334% and PT Saka Energi Muara Bakau with 11.666%. Activities are carried out in coordination with SKK Migas, the entity representing the Indonesian government.
Statoil to add third platform at Peregrino Phase II
The Peregrino Phase II field development will access new acreage out of reach of its current two wellhead platforms and floating production, storage, and offloading vessel. The contract was let in June 2016 (OGJ Online, June 28, 2016). According to Heerema Fabrication Group, the 8-legged jacket will include a wellhead platform with a drilling unit (WHP-C) tied back to the existing FPSO.
The 135-m Peregrino jacket will have a 66 x 53-m footprint, weighing 9,300 tonnes (excluding 12 piles). The company, which is constructing the jacket on behalf of South Atlantic Holding BV on behalf of Statoil ASA, will start construction in November at the Heerema yard in Vlissingen, the Netherlands. The installation is expected to sail away in October 2019.
The jacket will serve as a foundation for the topside, which will include the drilling and process facilities, utilities, power generation, living quarters, and a helideck with a design operational weight of 25,000 tonnes. The jacket also is designed for fresh water storage to assist drilling caissons for submerged pumps connected to the storage tanks.
Peregrino Phase II development will add 21 wells to the field, including 15 development wells and 6 water-injection wells. The third wellhead platform will be installed in 120 m of water and is expected to start production by yearend 2020. Peregrino Phase II is estimated to add recoverable resources of 250 million bbl of oil by the end of 2040, when the concession period ends (OGJ Online, Feb. 27, 2015).
PROCESSING — Quick TakesShell, Aramco finalize separation of Motiva assets
Saudi Aramco and Royal Dutch Shell PLC have completed their previously announced deal to divide up assets, liabilities, and businesses of their US-based refining and marketing joint venture Motiva Enterprises LLC (OGJ Online, Mar. 7, 2017).
Finalized on May 1, the transaction follows Aramco subsidiary Saudi Refining Inc. (SRI) and Shell US downstream affiliate SOPC Holdings East LLC's Mar. 6 signing of binding definitive agreements to end the partnership, Shell said.
Shell now holds sole ownership of the 235,000-b/d Norco refinery-where subsidiary Shell Chemical LP already operates a petrochemical plant-and the 242,250-b/d Convent refinery, which Motiva previously announced will be integrated to create the Louisiana Refining System (OGJ Online, Aug. 12, 2016).
Additionally, Shell remains owner of 11 distribution terminals as well as Shell-branded markets in Alabama, Mississippi, Tennessee, Louisiana, a portion of the Florida Panhandle, and the US Northeast, all of which are now fully integrated with Shell's North American downstream business, the company said.
Alongside retaining 24 distribution terminals and the Motiva name, SRI has taken 100% ownership of the 600,000-b/d Port Arthur, Tex., refinery and maintains an exclusive, long-term license to use the Shell brand for gasoline and diesel sales in Georgia; North and South Carolina; Virginia; Maryland; Washington, DC; the eastern half of Texas; and much of Florida.
Petrobras to shed Texas refinery
Petroleo Brasileiro SA (Petrobras) has added the proposed sale of subsidiary Pasadena Refining Systems Inc.'s (PRSI) 100,000-b/d refinery in Pasadena, Tex., to a revised divestments portfolio recently approved by the company's executive board following a mid-March decision on the divestment plan from Brazil's Federal Court of Accounts, Tribunal de Contas da Uniao (TCU).
In order to comply with procedures as set forth by Petrobras's 2017-21 strategic plan as well as TCU's Mar. 15 ruling on the company's revised divestment methodology, any potential opportunities to sell the refinery will individually be submitted to the company's executive board, and if approved, will be disclosed to the market in a timely manner, according to separate releases from Petrobras and Brazilian government.
Petrobras's newly approved divestment portfolio now seeks to raise $21 billion in 2017-18, up from the previously estimated target of $19.5 billion under the company's original 2017-21 strategic plan issued in September 2016.
ExxonMobil to buy aromatics plant in Singapore
ExxonMobil Chemical Co.'s Singapore affiliate has agreed to acquire a 1.4 million-tonnes/year aromatics plant on Jurong Island in Singapore from Jurong Aromatics Corp. Pte. Ltd.
Once the deal closes, which is expected in this year's second half, the plant will increase ExxonMobil's Singapore aromatics production to more than 3.5 million tpy, of which 1.8 million tpy will be paraxylene.
Singapore is home to ExxonMobil's largest integrated refining and petchem complex, which has an oil processing capacity of 592,000 b/d and includes two world-scale steam crackers.
Singapore's integrated petrochemical complex can process a wide range of feedstocks, from light gases to crude oil. Later this year, the complex will begin the phased startup of 230,000-tpy specialty polymers facilities that will produce halobutyl rubber and performance resins for adhesive applications.
The company earlier this year approved a project at the complex to expand production of high-quality lubricant base stocks (OGJ Online, Feb. 13, 2017).
LyondellBasell breaks ground on La Porte HDPE plant
LyondellBasell Industries NV has started construction of a grassroots high-density polyethylene (HDPE) plant at its petrochemical complex in La Porte, Tex. (OGJ Online, July 29, 2016).
Scheduled for startup in 2019, the proposed 1.1 billion-lb/year HDPE plant will be the first ever to use LyondellBasell's proprietary Hyperzone PE technology, a cascade-gas phase process based on the company's existing Multizone circulating-reactor technology, LyondellBasell said.
Part of LyondellBasell's $3-5 billion investment plans for in growth projects at the US Gulf Coast over the next 5 years, the new plant, once completed, will more than double the La Porte complex's annual HDPE capacity to 2 billion lb/yr (OGJ Online, Sept. 9, 2016).
The company said it selected its La Porte site for the new plant because of the complex's proximity both to price-advantaged feedstock from increased North American shale production and transportation infrastructure needed to ship product to global markets.
A final investment decision on development of a separate project to build the world's largest propylene oxide (PO) and tertiary butyl alcohol (TBA) plant at LyondellBasell's Channelview complex is scheduled for some time during this year's second half, the company said.
If completed, the PO-TBA plant would produce about 1 billion lb/year of PO and 29,000 b/d of oxyfuels beginning in 2020 (OGJ Online, June 3, 2016).
Earlier this year, LyondellBasell completed a project to expand ethylene capacity by 800 million-lb/year to 2.5 billion lb/year at its complex in Corpus Christi, Tex. (OGJ Online, Jan. 19, 2017).
TRANSPORTATION — Quick TakesFirms partner on Canadian propane export terminal
Koninklijke Vopak NV and AltaGas Ltd. have formed a joint venture to invest in development of the proposed Ridley Island propane export terminal (RIPET), near Prince Rupert, BC (OGJ Online, Oct. 24, 2016).
To be the first propane export terminal off Western Canada. the project will have a design capacity to ship 1.2 million tonnes/year of propane plus NGL mix (C3+), as well as a storage capacity of about 96,000 cu m, the companies said.
Vopak, whose investment is underpinned by long-term customer contracts and is fully aligned with its long-term strategic focus on gas storage and handling, will take a 30% ownership interest in RIPET, while AltaGas will hold the remaining 70% interest.
With regulatory and permitting processes for the project already under way, the proposed $450-500-million (Can.) RIPET will be built on a brownfield site subleased from Ridley Terminals Inc. (RTI) that features existing rail lines and RTI's existing marine jetty, which offers deepwater access to the Pacific Ocean.
As currently planned, the export terminal will receive about 50-60 railcars of C3+ from across British Columbia and Alberta via the existing CN rail network and be equipped to export between 20-30 cargoes/year of C3+ to destinations abroad, offering Western Canadian propane producers new markets, particularly in Asia Pacific.
The terminal's location will allow a 10-day shipping time to Asian-Pacific markets vs. a 25-day travel time from destinations at the US Gulf Coast, the companies said.
AltaGas, which previously completed front-end engineering and design on the project, already has received approval from Canada's National Energy Board for a 25-year license to export up to 1.35 million tpy of C3+.
With project construction scheduled to begin this year, the companies said they expect RIPET to be commissioned in first-quarter 2019.
As part of the new JV, AltaGas and Vopak also plan to explore other opportunities separate from RIPET to expand their relationship on Ridley Island, where both companies hold additional land rights.
