US production capabilities: GOM Production Poised to Set New Records

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GOM Production Poised to Set New Records

 

Oil production in the U.S. Gulf of Mexico (GoM) is poised to set new records in the imminent future.

That’s what energy research and business intelligence company Rystad Energy said in a statement posted on its website recently.

Rystad forecasts that 2019 oil output from the region will average 1.95 million barrels per day (bpd), with some months “potentially touching the two million bpd ceiling”. GoM oil production averaged 1.28 million bpd in 2013 and steadily rose to average a record high of 1.79 million bpd in 2018, Rystad highlighted.

“With earlier than planned production, Appomattox will be a key growth contributor to help push U.S. Gulf of Mexico oil production toward a new record high before year-end,” Joachim Milling Gregersen, an analyst on Rystad Energy’s upstream team, said in a company statement.

The deepwater Appomattox project is Shell’s largest floating platform in the GoM, according to Shell’s website. The company produced first oil from the development last month and anticipates an average peak annual production of 175,000 barrels of oil equivalent (boe) from the project. Rystad forecasts that plateau production at the Appomattox development will be around 140,000 boe per day.

Shell will be one of the top 2019 GoM equity producers, according to a list published by Rystad back in April. Other top equity producers from the region this year, according to Rystad’s list, will include BP, Equinor and ExxonMobil. A combined Chevron and Anadarko Petroleum entity took first place in the list, with Rystad predicting that such a company would produce just above 400,000 boe per day.

Chevron ended up bowing out of the chase for Anadarko after Occidental Petroleum made a proposal to acquire the company. Last month, Occidental agreed to buy Anadarko for $57 billion.

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This is older but still relevant.

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BP just discovered a billion barrels of oil in the Gulf of Mexico

Published Tue, Jan 8 2019 12:52 PM ESTUpdated Tue, Jan 8 2019 3:43 PM EST

 

• BP discovers 1 billion barrels of oil at its Thunder Horse field in the Gulf of Mexico.
• The oil giant also says it will spend $1.3 billion to develop a third phase of its Atlantis offshore field south of New Orleans.
• BP credits its investment in advanced seismic technology for speeding up its ability to confirm the discoveries.

BP’s investment in next-generation technology just paid off to the tune of a billion barrels of oil.

The British energy company has discovered 1 billion barrels of crude at an existing oilfield in the Gulf of Mexico. BP also announced two new offshore oil discoveries and a major new investment in a nearby field.

 

BP is the Gulf of Mexico’s biggest producer, and it’s making strides to hold that title.

BP now expects its fossil fuel output from the region to reach 400,000 barrels of oil equivalent per day by the middle of the next decade. Today, it produces about 300,000 boepd, up from less than 200,000 boepd about five years ago

On Tuesday, the company said it will spend $1.3 billion to develop a third phase of its Atlantis field off the coast of New Orleans. Scheduled to start production in 2020, the eight new wells will add 38,000 bpd to BP’s production at Atlantis. The decision comes after BP found another 400 million barrels of oil at the field.

BP made the massive 1 billion-barrel discovery at its Thunder Horse field off the tip of Louisiana.

Executives are crediting their investment in advanced seismic technology and data processing for speeding up the company’s ability to confirm the discoveries at Atlantis and Thunder Horse. BP says it once would have taken a year to analyze the Thunder Horse data, but it now takes just weeks.

 

“We are building on our world-class position, upgrading the resources at our fields through technology, productivity and exploration success,” Bernard Looney, BP’s chief executive for production and exploration, said in a statement.

Just northeast of Thunder Horse, BP also announced new discoveries at fields near its Na Kika platform.

BP says it plans to develop reservoirs at its Manuel prospect, where Shell holds a 50 percent stake. Producers also found oil at the Nearly Headless Nick prospect near Na Kika, where BP has a 20.25 percent working interest.

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OH WOW, the GoM offshore industry must be in cahoots and or must be colluding with the shale industry, they are using "breakevens" to talk about the offshore industry!!!. According to Mike, the shale industry "invented" the breakeven sham/scam!!

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As energy world focuses on Permian, Gulf makes its own comeback

The attention of the energy industry has focused in recent years on the Permian Basin, the once tired West Texas oil field that roared back to life when hydraulic fracturing and horizontal drilling freed the vast reserves locked in its shale. But as the Permian gathers the attention, another aging oil field is making its own comeback.

The Gulf of Mexico is producing a record of almost 2 millions barrel of crude oil a day and expected to increase its output each year over at least the next five years as new projects begin operation and new discoveries in deeper waters are made. After struggling in the aftermath of the oil bust as investment shifted onshore, the Gulf has found new life as oil companies have succeeded in lowering costs, and market dynamics have made the heavier crude produced in the Gulf more valuable and sought after by refineries from the Gulf Coast to Asia.

The energy research firm Wood Mackenzie projects Gulf drilling activity to jump 30 percent this year after four consecutive years of declines. The federal government forecasts production to grow another 15 percent next year to 2.3 million barrels a day as as oil companies, particularly the biggest players, find advantage in deepwater wells that deplete far more slowly than shale reservoirs.

 

 

 

“The quality of Gulf crude as well as the longer life of offshore wells make it just as attractive as shale to large producers today,” said Sandy Fielden, Morningstar’s director of oil and products research.

As in the Permian and other shale plays, producers that have found ways to make money with lower crude oil prices have opened the spigots. The Permian Basin and the Gulf of Mexico account for about half nation’s output, now at a record 12 million barrels a day.

Cutting costs

 

The average cost of extracting oil barrels from deepwater wells has plunged by more than 50 percent in five years, according to Wood Mackenzie, as companies have standardized project designs and equipment. They also focused drilling projects near existing platforms that can be connected to the new wells via underwater pipelines and umbilicals, which is far less costly than building and installing new platforms.

The breakeven price for profiting off of deepwater wells has fallen from about $70 a barrel a few years ago to closer to $40, according to the top Gulf producers BP and Royal Dutch Shell. As one measure of the vast gains in efficiency, consider this: Gulf producers are pumping twice as much crude with a quarter of the drilling rigs used in the mid-1990s.

“The deepwater is thought of as an expensive and difficult place to be,” said Starlee Sykes, BP's regional president for the Gulf. “Recent developments are changing that.”

The world’s biggest oil companies, including BP, Shell and Chevron dominate much of the Gulf, and other top global players such as the French oil major Total, Norway’s state energy company Equinor and The Woodlands’ Anadarko Petroleum also are investing more in the region. Asian energy companies, valuing the political stability of the United States over potentially bigger returns in more volatile regions such as Africa and Latin America, also are developing projects in the Gulf.

 

Those firms include include China National Offshore Oil Corp., called CNOOC, and the Japanese companies Inpex Corp., Mitsui Oil and Marubeni Oil & Gas.

Shell completed a series of smaller expansions last year and, this fall, will put its multibillion-dollar Appomattox platform in operation about 80 miles of the Louisiana Coast to target deep geologic layers believed to hold much on the undiscovered oil in the Gulf. Appomattox will be followed in 2021 with the Vito platform about 150 miles southeast of New Orleans.

After Vito, Shell expects to home in on its Whale discovery — announced a year ago — in the southwest Gulf almost 200 miles south of Houston. Rick Tallant, Shell vice president for production in the Gulf, said a final decision for a multibillion-dollar development of Whale is likely in 2020.

 

“The industry in general is starting to reinvest back into the Gulf of Mexico,” Tallant said.

In January, for example, BP said it would spend $1.3 billion to expand its Atlantis development about 150 miles south of New Orleans. BP said it produces more than 300,000 barrels of oil equivalent a day from the Gulf and plans to exceed 400,000 barrels daily by the mid-2020s.

The Gulf also is attracting further investments from smaller players such as the Houston companies Talos Energy, Fieldwood Energy, W&T Offshore and Houston Energy.

Ron Neal, co-founder of Houston Energy, said these companies are taking a contrarian approach, targeting the Gulf when shale is all the rage and buying leases at significant discounts to acreage in the Permian Basin. The Gulf’s wells are costlier to develop up front, he said, but they can churn out high volumes of oil for many years, unlike shale wells, in which production drops sharply after the first year or so.

 

“The deepwater is healthy,” Neal said. “We just try to be consistent and not reactionary, and it’s worked pretty well.”

To Mars and beyond

Wood Mackenzie predicts the next big project to move forward could be Chevron’s and Total’s 2017 Anchor discovery more than 100 miles south of New Orleans. That development could trigger more than $10 billion in investments.. Last last year, Chevron’s new Big Foot platform came online east of the Anchor find.

 

 

In addition to lower lease costs and longer well life, another factor is driving increased activity in the Gulf of Mexico: premium prices for its oil. Gulf wells produce a medium grade crude and the benchmark, called Mars, is selling at $6 a barrel more than lighter crude produced in West Texas — a premium of about 15 percent and the highest differential for Mars sine 2013.

The reason: a global shortage of the heavier crudes preferred by refiners from the Gulf Coast to Asia. Several developments have cut the supply of heavier crudes on the market, including OPEC’s production cuts, U.S. sanctions on Iran and Venezuela, and OPEC-style output reductions put in place the government of Alberta, Canada to try to lift prices of the heavy crude produced in the province’s oil sands.

Analysts expect Gulf of Mexico oil to fetch higher prices at least though the end of this year.

“As the U.S. consolidates its position as one of the world’s largest producers and a major exporter,” said Fielden, the Morningstar analyst, “the long-term value and importance of offshore production shouldn’t be underestimated.”

 

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Deepwater Gulf of Mexico - America's Expanding Frontier
SOURCE: U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico OCS Region

PRODUCTION RATES

High well production rates have been a driving force behind the success of deepwater operations.

Figure 67a illustrates the highest deepwater oil production rates (monthly production divided by actual production days).

Figure 67a. Maximum production rates for a single well within each water-depth category for deepwater oil production. (Click the image to enlarge)

For example, a well within Shell�s Bullwinkle field produced about 5,000 BOPD in 1992. In 1994, a well within Shell�s Auger field set a record, producing about 10,000 BOPD.

From 1994 through mid-1999, maximum deepwater oil production rates continued to climb, especially in water depths between 1,500 and 4,999 ft (457 and 1,524 m).

Horn Mountain came on line in early 2002 in 5,400 ft (1,646 m) water depth with a single well maximum rate of more than 30,000 BOPD

The deepest production is currently held by Camden Hills in 7,216 ft (2,199 m) water depth.

Figure 67b shows maximum production rates for gas.

Figure 67b. Maximum production rates for a single well within each water-depth category for deepwater gas production. (Click the image to enlarge)

These rates hovered around 25 MMCFPD until a well in Shell�s Popeye field raised the deepwater production record to over 100 MMCFPD in 1996. Since then, the deepwater has yielded even higher maximum production rates.

In 1997, Shell�s Mensa field (5,379 ft [1,640 m] water depth) showed the excellent potential for deepwater production rates beyond the 5,000 ft (1,524 m) water depth. The record daily oil and gas production rates (for a single well) are 41,532 BOPD (Troika) and 145 MMCFPD (Mica).

Figure 68a shows that the average deepwater oil completion currently produces at 20 times the rate of the average shallow water (less than 1,000 ft [305 m]) oil completion.

Figure 68a. Average production rates for shallow-water and deepwater oil well completions. (Click the image to enlarge)

The average deepwater gas completion currently produces at 8 times the rate of the average shallow-water gas completion (figure 68b).

Figure 68b. Average production rates for shallow-water and deepwater gas well completions. (Click the image to enlarge)

Deepwater oil production rates increased rapidly from 1996 through 2000 and remained steady since that time.

Deepwater gas production rates rose from 1996 to mid-1997 and then stabilized at the current high rates.

Two trends are readily apparent in figures 69a-b.

Figure 69a. Deepwater oil production profiles (oil wells coming onstream between 1992 and 2002). (Click the image to enlarge)

Figure 69b. Deepwater gas production profiles (gas wells coming onstream between 1992 and 2002). (Click the image to enlarge)

First, average oil and gas production rates per well are increasing and, secondly, production rates are declining from their peaks more rapidly in recent years.

These figures plot monthly average oil and gas production rates for all wells completed in a specific year.

For example, in figure 69a, the 1992 line represents oil well production for oil wells completed in 1992 divided by the number of oil wells completed in that year.

The 1992 line tracks production from these completions in successive years.

Figures 70a (oil) and 70b (gas) compare maximum historical production rates for each lease in the GOM, i.e., the well with the highest historical production rate is shown for each lease.

Figure 70a. Maximum historical oil production rates for Gulf of Mexico wells. (Click the image to enlarge)

Figure 70b. Maximum historical gas production rates for Gulf of Mexico wells. (Click the image to enlarge)

These maps show that many deepwater fields produce at some of the highest rates encountered in the GOM.

Figure 70a also shows that maximum oil rates were significantly higher off the southeast Louisiana coast than off the Texas coast.

Figure 70b illustrates the high deepwater gas production rates relative to the rest of the GOM.

Note also the excellent production rates from the Norphlet trend (off the Alabama coast) and the Corsair trend (off the Texas coast).
 

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Deepwater Texas Oil Port Developer Seeks MARAD License

Dallas-based Sentinel Midstream, LLC reported Monday that its Texas GulfLink, LLC subsidiary last week submitted a license application with the U.S. Maritime Administration (MARAD) to construct and operate a deepwater crude oil export facility off the coast of Freeport, Texas.

According to Sentinel, the proposed Texas GulfLink terminal would be capable of fully loading very large crude carrier (VLCC) vessels. Currently, the U.S. is home to just one deepwater crude oil port facility: the Louisiana Offshore Oil Port (LOOP).

The Texas GulfLink project calls for developing an onshore oil storage terminal connected via 42-inch-diameter pipeline to a manned offshore platform approximately 30 miles off the Gulf Coast, Sentinel stated. Oil would be transported from the platform to two single point mooring buoys, which would enable VLCCs to receive 2 million barrels of crude oil loaded at rates up to 85,000 barrels per hour, the firm added.

“With the submission of the license application to MARAD, Texas GulfLink has completed a major milestone towards receiving approval to construct and operate a deepwater crude oil export facility,” Jeff Ballard, Sentinel’s president and CEO, said in a written statement emailed to Rigzone. “As the neutral infrastructure export solution for shippers, Texas GulfLink will provide a necessary crude oil export outlet for the expected increase in U.S. crude oil production.”

Sentinel added that Cresta Fund Management is providing project financing and Abadie-Williams served as Texas GulfLink’s primary engineering and regulatory consultant.

“We are pleased with the commercial support Texas GulfLink has received and the continued strong interest from shippers who recognize the need for additional export capacity,” noted Chris Rozzell, Cresta managing partner. “By reducing capacity constraints in Gulf Coast ports and creating an economic oil export outlet, Texas GulfLink will allow U.S. oil producers to continue to develop and increase U.S. oil production without potential production curtailments due to lack of export capacity.”

Other firms vying to develop deepwater crude oil port facilities offshore Texas include Trafiugura US Inc. and Enterprise Products Partners L.P. Trafigura’s Texas Gulf Terminals project would be located near Corpus Christi. Enterprise’s Sea Port of Texas (SPOT) project would be located offshore Freeport. Additionally, Lone Star Ports, LLC – a joint venture of The Carlyle Group and The Berry Group – have proposed building an onshore export facility near Corpus Christi that could load VLCCs.

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Texas Petro Index March/Q1: Activity Down But TX Oil & Gas Economy Expanding

AUSTIN, Texas – Curious trends are happening in the Texas oil and gas industry, according to the Texas Alliance of Energy Producers March Texas Petro Index (TPI). Despite a decline in the March TPI to 212.4 and in the first quarter 2019, prices continue to improve and Texas crude oil production is still breaking records. A monthly measure of growth rates and cycles in the Texas upstream oil and gas economy, the TPI is based on indicators such as rig count, drilling permits, well completions, and employment, which all remained in decline in March.

“Typically, these E&P indicators decline during an observable, sustained contraction in oil and gas activity, but that doesn’t appear to be what we’re seeing now,” Karr Ingham, Petroleum Economist for the Texas Alliance of Energy Producers and creator of the TPI. “I do think these decreases can partly – even largely – be attributed to the sharp and unexpected fourth quarter 2018 crude oil price declines, but clearly there are other forces at work. These have become increasingly evident over the course of the current recovery and expansion from the 2014-2016 industry downturn.”

These forces are the ever-higher efficiencies achieved by Texas oil and gas operators, supported by the numbers. With crude oil production continuing to set milestones, the March monthly average rig count fell below 500, the fourth straight month of decline, compared to a monthly average of 904 in December 2014. The number of drilling permits issued in the first quarter is down by about five percent compared to year-ago levels and is off by nearly 40 percent compared to the 5,367 permits issued in the first quarter 2014.

Direct upstream (exploration and production) industry employment is on the wane as well after reaching a cyclical peak in December 2018.  Seasonally adjusted numbers compiled by the Federal Reserve Bank of Dallas, with further adjustments by the Texas Alliance of Energy Producers (to strip out the few “mining” jobs in Texas that are not oil and gas related) suggest the loss of about 3,500 oil and gas E&P jobs from December to March. Further, the March estimate is down by over 70,000 compared to the all-time peak employment total in December 2014.

Industry employment and crude oil production estimates in March suggest that for every one direct upstream oil and gas employee, about 700 barrels of oil are produced, compared to about 170 barrels per employee in 2009.

Crude oil production continued its upward ascent through the first quarter, however, with daily production exceeding five million barrels for the first time according to Alliance estimates (based on data from the U.S. Energy Information Administration (EIA) and the Texas Railroad Commission).

“Given current price levels, which continue to improve, the Texas upstream oil and gas economy remains in expansion mode,” said Ingham. “But the nature of oil and gas economic growth in Texas is different in 2019 largely because it has become perfectly apparent that Texas oil and gas companies can produce more crude oil with fewer resources deployed.”

The March 2019 Texas Petro Index of 212.4 was down from the February TPI of 213.1, and the December (year-end) 2018 index of 212.9 – and more than 100 points (about 32%) below its November 2014 peak. In fact, the Texas Petro Index has generally been in a state of mild decline since its cyclical peak in October 2018.

Crude oil pricing itself is well below the June 2014 cyclical peak in crude oil prices of over $100/bbl, and natural gas pricing in Texas is increasingly wretched in early 2019 thanks to continued deep discounts in Permian gas prices. The Texas Alliance of Energy Producers Texas Petro Index is based at 100.0 in January 1995.

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Oil & Gas Leaders Look for Cost Reduction and Efficiency Gains

 

Houston – Speaking at the closing of the AIPN 2019 International Petroleum Summit (IPS), Ryan Lance, Chairman and Chief Executive Officer of ConocoPhillips spoke about his company’s “hyper focus on returns” highlighting that the “returns the energy industry has generated have been negative over the last 10 to 15 years. Investors are frustrated. We chase the cycle up only, they have to chase the cycle back down on the back side. We recognize it’s a mature industry growing at 1 percent per year. There’s a lot of companies, some tremendous companies … that have dramatic growth profiles. But when they put a hundred percent of their cash flow back into the business, don’t pay the shareholder a fair amount of money, they’re actually destroying value in the long run.

You’ve got to pay your shareholder upfront, you’ve got to be able to grow and develop your company off the cash flow that’s left over and you’ve got to have a focus on returns on capital employed.”

Technology was a constant theme throughout the two days of the IPS with many of the speakers agreeing that technology is going to play a great part in generating future value. Ryan Lance said, “The revolution that we’ve got going on inside our company is embracing technology, innovation and analytics…is it’s not so much about adding another rig it’s about how do you get more work done with that rig that you’ve got.”

 

Alma Del Toro President, Blue Bull Energy believes that, “Technology, such as unmanned platforms, will change the entire nature of the joint operating agreements. Technology is changing the game plan.” However, she pointed out that, “For a CEO choosing the right technology presents its own challenges.”

With panels on Venezuela and Brazil as well as several sessions on Mexico delegates recognized that South America, despite the huge amount of change in the last six months, would provide important opportunities for the industry’s expansion. When commenting about the political changes in Mexico Alma Del Toro said, “Shell, Murphy and Jaguar have reaffirmed my belief that the new administration has not changed much and that Mexico is open for business. Permits are getting issued and nothing has stopped.”

About the AIPN: The Association of International Petroleum Negotiators is an independent not-for-profit professional membership association that supports international energy negotiators around the world and enhances their effectiveness and professionalism in the international energy community. Founded in 1981, AIPN has over 3,000 members in more than 110 countries, representing international and national oil and gas companies, governments, law firms and academic institutions.

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Examining How Industry Giants Reduced Operational Costs By Going Digital

 

Last year’s tumultuous oil prices saw WTI and Brent both start the year at over $60 for the first time since 2014, the benchmark year for pre-crash prices. Hopes of a true price rebound began to grow as both commodities hit four-year highs several times throughout 2018. For an online archive of how intense the hype became, simply search “will oil prices reach $100 again.” The result is pages upon pages of industry and finance headlines examining the possibility of $100 barrels — the overwhelming majority of which were published in 2018. While the consensus was split, optimists were about to learn a lesson in false hope. WTI and Brent closed the year well below $60 per barrel, prompting the U.S. Energy Information Administration (EIA) to reduce both its 2018 and 2019 forecasts in early December. To add insult to injury early this year, 2019 forecasts were further reduced, along with 2020 forecasted prices. If additional evidence was necessary to illustrate that low prices are the “new normal” for the O&G industry, Q1 of 2019 provided a solid case.

O&G producers and service companies don’t need to reinvent the wheel in order to reduce operational costs. The most capital-intensive
projects in the industry have proven digitization as a model for reducing operational costs. In this article, we take a look at what analysts learned from the industry’s digital pioneers before examining how to scale the same principles to reduce costs and safeguard profit margins in the face of unpredictable market prices.

How the Biggest E&P Projects Safeguard Profits

Logically, cost discipline has been the dominant business strategy of O&G producers since 2014. Any hope of realizing profit in the face of dwindling revenues required significant reductions in what was already one of the biggest upstream cost risks: operational costs. The upstream companies that were able to weather the latest price crash found ways to trim the fat and implement lean operating principles. However, this was not the case for the biggest ventures in oil and gas extraction: offshore rigs. Whether it was a response to the 2008 crash or simply the capitalist pursuit of profit, stakeholders in these mammoth projects had already identified, refined and implemented new ways to reduce operational costs.

How did they manage? By embracing the next step in the evolution of industrialization: digitization.

It was mid-2014 when McKinsey & Company published a whitepaper titled “Digitizing Oil and Gas Production.” Using North Sea offshore rigs as benchmarks, they observed that while production efficiency had dropped in the past decade, the performance gap between industry leaders and all others had nearly doubled between 2010 and 2012. Looking for what sparked the differentiation, analysts examined the role of technology. Production was considered “digitally-capable” at this point, with any average offshore rig using upwards of 40,000 sensors to collect massive amounts of complex data. So how did the leaders manage to pull away from the pack? By successfully integrating all that data.

The E&P companies that were able to use data effectively increased production efficiency by ten percent and saw $220 million to $260 million dollar increases to their bottom line. And remember, this shift occurred before the 2014 crash in oil prices. The advantages gained through production efficiency became exponentially more valuable in the face of shrinking revenues as global oil prices plummeted.

What Does “Successful Integration of Data” Mean?

 

Data can be used in a lot of ways, from reducing unplanned rig downtime by informing predictive maintenance schedules, to enabling the complete automation of complex, unconventional drilling maneuvers. In fact, automation (the conversion of manual processes to automatic ones) is presently the ultimate means of utilizing data to increase efficiency. Where the Industrial Revolution was marked by the use of iron to enable mechanization, the digital revolution of the 21st century requires vast amounts of data to enable the next step in our tech evolution: automation. Five years ago, when McKinsey & Company identified automation as a “clear competitive imperative” for the O&G industry, prices were over $100 per barrel and the case for large capital investment in new tech was a hard sell. However, in the new normal of sub-sixty dollar barrels, the urgency of automation is clear.

Avoid a Cart-Before-The-Horse Scenario: Automation Is Data-Driven

As previously mentioned, automation requires data – and lots of it. Operations such as rigs and refineries are rife with data-capturing opportunities: every sensor, gauge and meter can go from simply displaying information to storing it. However, indiscriminate data collection is unmanageable and will certainly not lead to production efficiencies. Before the rigs examined by McKinsey & Company increased profits by $200 million through intelligent data integrations, stakeholders began with a vision for how the information would be used. This way, only digital outputs that furthered the end goal were selected for collection.

Scaling Down: The Path to Automation for On-Shore Producers and Service Companies

Various automations are available to O&G production and service companies without the need for data collection or other R&D. These ready-made solutions reduce operational costs for some common standard processes such as executing a slide or scheduling tool maintenance. If you can purchase the tech, you are able to reduce operational costs. These products are good for your bottom line but they do not result in a true competitive advantage. Pulling away from the pack and creating the significant production gap achieved by the leaders in our case study requires vision, creativity and asking the right questions. Where are the opportunities in your operations? Where is data not being captured? Or, which processes fail to leverage captured data? These kinds of questions produced a proven digital model that also performs at smaller scales. Careful examination of your processes will also lead to a well-informed digital roadmap for reducing operation costs. Consider what can be learned from the timing of the industry leaders in the McKinsey & Company whitepaper as well. Rather than reacting to market changes, these innovators made proactive capital investments before the need was even apparent.

There’s another advantage to following in the footsteps of giants — you don’t need an in-house team of programmers to create bespoke software tools. Thanks to third party specialists, every step of digitization — from the overall vision to field execution — is guided by experts. The management of field crews is one of the biggest opportunities to capture data and improve processes through automation. Even as the digital revolution permeates all other aspects of E&P, field operations remain heavily dependent on paper, leading to revenue leakage and high operational costs. The disconnect between the field and the leadership team results in information lags and errors, making effective cost management impossible.

At Aimsio, we’re familiar with the challenges you face when it comes to managing remote field operations. We also happen to be specialists in creating digital solutions for O&G producers and service companies. To see how our platform makes real-time cost management possible by capturing data in the field, head over to www.aimsio.com. 

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Good for the exports of GoM produced oil, but I dont see anyone whining about preventing the export of these crude oils like they do about shale!!!!!

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Record Number Of VLCCs Loading At Louisiana Export Port: Sources

 

Medium-sour crude from the U.S. Gulf of Mexico are being snapped up by overseas buyers, paving way for a record six supertankers to load at the Louisiana Offshore Oil Port (LOOP) in a matter of weeks, according to people familiar with the matter.

The six scheduled loadings in late May and early June would double the record of Very Large Crude Carriers (VLCCs) reached in December. An unusual influx of Gulf of Mexico crudes to the U.S. deepwater export port and weakening prices are contributing to the exports, according to one of the people close to the matter.

Mars Sour, a Gulf of Mexico crude produced by Royal Dutch Shell Plc, traded at a $4.40 a barrel premium to U.S. crude futures on Monday, falling from its 2019 peak of around $8.10 premium in mid-February.

Following U.S. sanctions on Venezuela and Iran, and production cuts by the Organization of the Petroleum Exporting Countries, U.S. medium-sour grades including Mars are helping fill Asian oil buyers' needs for new sources of supply.

"We've seen very good global demand for medium and heavy sour crude oil," said James Chrystal, an oil trader at Mercuria Energy Group.

New Prime, chartered by Shell, began loading crude at LOOP on Monday, following two departures since Friday of supertankers chartered by China's Unipec and Mercuria, according to trade sources and data from Refinitiv Eikon and vessel-tracking service Kpler.

Shell and Unipec did not immediately respond to requests for comment. Mercuria declined to comment on specific sales or cargo movement.

Coswisdom Lake, a tanker chartered by Unipec according to trade sources and Refinitiv, left last week with almost 2 million barrels for Shuidong port in China. Captain X. Kyriakou, chartered by Mercuria, also nearly fully loaded, departed for an unknown destination in Asia on Monday, the data showed.

Three other supertankers, are expected to load at LOOP through the middle of June, the person familiar with the matter said.

In recent weeks, more crude produced in the U.S. Gulf of Mexico has been piped to LOOP for loading onto vessels instead of to domestic refiners, trade sources said.

In May, U.S. refiners imported a larger amount of medium sour crude from Iraq, Nigeria, Brazil and Angola, lowering U.S. demand and prices for Mars crude. Lower prices spurred increased overseas purchases, trade sources said.

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Top 12 Recent Gulf of Mexico Discoveries

Murphy Oil hits pay zone at Samurai prospect.

 

Prospect, Field, Block	Well	Ft. of net pay/production	Operator	Depth (ft)	Completion date
Samurai, Green Canyon Block 432	2OCS G32504	150 ft of net pay (two Miocene zones)	Murphy Oil Corp.	Drilling 32,000 ft	Sept. 2018
Mississippi Canyon Block 612	1 (BP) OCS G33166	800 ft of net pay (Norphlet)	Shell Oil Co.	Drilling 29,600 Water: 7,300	May 2018
South March Island Block 71	1-F OCS G34266 2-F OCS G34266	4 Mbbl of oil/d (combined from Pliocene sands)	Byron Energy Ltd.	n/a	Apr. 2018
Ballymore, MIssissippi Canyon Block 607	1(ST) OCS G3451	607 ft of net pay (Miocene)	Chevron Corp.	Drilling: 29,194 Water 6,600	Mar. 2018
South Marsh Island Block 71	3-F OCSG34266	211 net ft of oil pay	Byron Energy Ltd.	Water: n/a Drilling: 8,615	Apr. 2018
Whale, Alamonos Canyon Block 772	1(BP) OCS G35153	1,400 net ft of oil-bearing pay	Shell Oil Co.	Water: n/a Drilling: 22,948	June 2017
Pompano platform, Mississippi Canyon Block 28	4 OCS G09771	153 ft of net oil pay	Stone Energy Corp.	Water: n/a Drilling: 12,176	Dec. 2017
Tornado, Green Canyon Block 281	2SS (ST) OCSG3342	12.35 Mboe/d (83% oil)	Talos Energy LLC	Water: 2,750 Drilling: 21,057 (tvd)	Dec. 2017
Ship Shoal Block 300	5-B (ST) OCS G07760	173 ft of hydorcarbon pay with peak flow of 1.1 Mboe/d	W&T Offshore	Water: n/a Drilling: 5,772	Nov. 2017
Tornado, Green Canyon Block 281	2SS (ST) OCS G33242	297 net ft of oil pay	Talos Energy LLC	n/a	Oct. 2017
Rampart Deep, Mississippi Canyon Block 117	1 OCS G32299	130 ft of liquids-rich pay	Deep Gulf Energy Co.	Water: 2,700 Drilling: n/a	Sept. 2017
Constellation, Green Canyon Block 627	3SS OCS G25174	120 ft of net pay	Anadarko Petroleum Corp.	Water: 4,400 Drilling: n/a

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Shell to make FID on giant Gulf of Mexico oil find in 2020

Oil major Shell is working on making a Final Investment Decision in 2020 on its large deepwater Gulf of Mexico oil find named Whale.

Shell made the discovery, one of its largest exploration finds in the past decade in U.S. Gulf of Mexico, back in February 2018.

At the time, the company said it had encountered more than 1,400 net feet (427 meters) of oil-bearing pay, adding it would take further appraisal drilling to further delineate the oil discovery and define development possibilities.

In a conference call on Thursday, Shell CEO Ben van Beurden said: “When we announced the Whale discovery last year, I said were looking to accelerate the development cycle and bring the project on stream faster. So I’m pleased to announce that we’re already assessing the results of the exploration and appraisal wells that we have drilled at Whale.”

Van Beurden said the development options are still under assessment, with a focus on standardization, replication, and incorporating the learnings from another Gulf of Mexico development – the Vito.

Shell made the final investment decision (FID) for Vito development in April, 2018. The Vito development has an estimated, recoverable resource of 300 million boe. It is currently scheduled to begin producing oil in 2021.

Back to the Whale project, Van Beurden on Thursday said the current work on the project should allow us Shell to accelerate timelines.

“And depending on the outcomes, of course, we could take a final investment decision as early as next year,” Van Beurden said.

Asked to provide insight on the actual size of the Whale discovery, Van Beurden said he could only say the project was “a world-scale one,” not going into exact numbers as further appraisal needs to be done.

The Whale project is operated by Shell (60%) and co-owned by Chevron U.S.A. Inc. (40%). It was discovered in the Alaminos Canyon Block 772, adjacent to the Shell-operated Silvertip field and approximately 10-miles from the Shell-operated Perdido platform. Shell expects its global deep-water production to exceed 900,000 boe per day by 2020, from already discovered, established areas.

 

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W&T Offshore Inc. has discovered oil in the Gladden Deep exploration well in the U.S. Gulf of Mexico, project partner Kosmos Energy announced Tuesday.

Kosmos, which has a 20 percent working interest, said Gladden Deep is a subsea tieback expected to be brought online through the existing Gladden pipeline to the Medusa spar in fourth quarter 2019.

Gladden Deep is the first of a four-well infrastructure-led exploration (ILX) program in the Gulf of Mexico in 2019.

Later this year, Kosmos will drill the Moneypenny prospect (third quarter) followed by the Oldfield and Resolution prospects (fourth quarter). The three prospects are targeting around 100 million barrels of oil equivalent (MMboe) net to Kosmos.

Preliminary analysis of drilling and wireline logging results suggest the recoverable resource is expected to be in line with predrill estimates of 7 MMboe gross.  

“Although Gladden Deep is the smallest prospect in this year’s drilling campaign, it is a prime example of our ILX strategy in action – targeting high margin, high return barrels that can be quickly brought online through existing facilities,” Kosmos CEO Andy Inglis said in a company statement. “The development of Gladden Deep has a full cycle rate of return of over 100 percent at $60/barrel Brent. This discovery continues the strong momentum we have seen in our Gulf of Mexico business unit, following the recent lease sale results and increased production from the Tornado-3 well coming online.”

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new pipeline projects in the permian

Wink to Webster Texas Pipeline

• Companies: Plains All American Pipeline L.P. and Exxon Mobil, Lotus Midstream LLC

• Capacity: 1 million b/d capacity

• Projected In-Service: In-Service: Q1 – Q2 2021

• More Info:https://winktowebsterpipeline.com/

 

Gray Oak

• Company: Phillips 66

• Capacity: 800,000 b/d capacity

• Projected In-Service: Q4 2019

• More Info:https://grayoakpipeline.com/

 

Cactus ii

• Company: Plains All American

• Capacity: 670,000 b/d

• Projected In-Service: Q4 2019 – Q2 2020

• More Info:https://www.plainsallamerican.com/about-us/subsidiary-websites/permian-projects

 

Jupiter Crude Pipeline

• Company: Jupiter Pipeline LLC

• Capacity: 1.1 million b/d

• Projected In-Service: Q3 2020

• More Info:https://www.jupitermlp.com/

 

Epic Crude Pipeline

• Company: EPIC Midstream Holdings

• Capacity: 900,000 b/d

• Projected In-Service: Q4 2019 – Q1 2020

• More Info:https://epicpipelinelp.com/projects/crude-pipeline/

 

 

Permian Global Access Pipeline

• Companies: Tellurian

• Capacity: 2.0 bcf/d

• Projected In-Service: 2023

• More Info: http://www.pgap.com/

 

Gulf Coast Express

• Companies: Kinder Morgan, Targa Resources, DCP Midstream

• Capacity: 2.0 bcf/d

• Projected In-Service: Q3 2019

• More Info: https://www.kindermorgan.com/pages/business/gas_pipelines/projects/kmtp/

 

Permian Highway Pipeline 

• Companies: Kinder Morgan, EagleClaw Midstream Ventures

• Capacity: 2.0 bcf/d

• Projected In-Service: Q4 2020

• More Info: https://www.kindermorgan.com/pages/business/gas_pipelines/projects/php/

 

Pecos Trail

• Companies: NAmerico Energy

• Capacity: 1.85 bcf/d

• Projected In-Service: Q3 2019

• More Info: https://www.namerico-energy.com/portfolio/energy/pecos-trail-pipeline/

 

Permian-Katy Pipeline 

• Companies: Sempra LNG & Midstream, Loews/Boardwalk Pipeline Partners

• Capacity: 2.0 bcf/d

• Projected In-Service: Q3 2020

• More Info: http://www.p2kpipeline.com

 

Whistler Pipeline

• Companies: Targa Resources, NextEra Energy Pipeline Holdings, WhiteWater Midstream and MPLX

• Capacity: 2.0 bcf/d

• Projected In-Service: Q4 2020

• More Info: http://www.targaresources.com/operations/operations-map

 

 

 

Grand Prix Pipeline

• Company: Targa Resources

• Capacity: 450,000 b/d

• Projected In-Service: Q2 2019

• More Info: http://www.targaresources.com/operations/operations-map

 

Epic ngl Pipeline

• Company: EPIC Midstream Holdings

• Capacity: 440,000 b/d

• Projected In-Service: Q3 2019

• More Info: https://epicpipelinelp.com/projects/ngl-pipeline/