ConocoPhillips in the Permian Basin: Competitive now, poised for growth

well pad
Drilling rig at the Mockingbird well pad, located near the Mockingbird Central Facility
by Jan Hester, photography by Patrick Currey

Although global oil and gas prices remain low, you’d never know it in Midland, Texas. It’s clear from a visit to the boom-and-bust city that the Permian Basin region of west Texas and southeastern New Mexico is back.

Since the early 1920s, when the Santa Rita discovery attracted wildcatters to the area, the basin has produced 29 billion barrels of oil. Yet experts believe the region’s best days could lie ahead, thanks to new extraction techniques that enable companies to unlock oil and gas trapped within its unique geology — stacked layers of hydrocarbon-bearing rock formations. According to a July 2016 analysis by research firm Rystad Energy, the “U.S. now holds more oil reserves than Saudi Arabia,” thanks in part to the Permian.

The Permian has long been a steady producer for ConocoPhillips and, because of its stacked geology, it offers tremendous opportunity for future large-scale growth.

The company currently holds approximately 1 million net acres in the Permian basin, including 75,000 in the resource-rich Delaware Basin and 48,500 in the Midland Basin.

Olds photo
Nick Olds, vice president, Mid-Continent business unit

Net production for the Permian in 2016 was 64,000 barrels of oil per day (BOED), including 15,000 BOED in unconventional production. Current production as of October 2017 was roughly 65,000 BOED, including 23,000 BOED operated and nonoperated unconventional.

Most development is focused on new unconventional plays, where appraisal drilling results are meeting expectations and development wells are targeting the most prolific and lower cost-of-supply zones. The company’s Mid-Continent business unit is also working to maximize base production by utilizing various technologies to improve recovery and value from older, conventional fields such as the Goldsmith, which began producing in the 1950s.

“The Permian holds so much potential in terms of new reserves and increased production,” said Nick Olds, vice president, Mid-Continent business unit. “Over the last several years, we’ve laid a solid, cost-effective foundation in the form of a new development, infrastructure and contracting strategy that is yielding results and will generate positive returns below $40 per barrel.”

“If I were to describe the Permian Basin, I would start with Delaware, a large strategic play for the company,” said Permian Development Manager Josh Viets.

Conoco­Phillips’ unconventional history in the Permian began in 2012, when it acquired acreage in the southern portion of the Midland Basin and the western side of the Delaware. In 2017, the business increased its drilling activity in the area.

“We’re on a large growth trajectory,” Olds said. “We currently have three rigs operating, and for a time we’ll have four — three in the Delaware and one chasing our conventional plays.  As we look forward to Q4 2018, we’ll have three dedicated to the Delaware at China Draw and Zia Hills (formerly Red Hills). We feel that three is the minimum optimum level where we can have one continuous frack crew to improve efficiency and reduce cost of supply.”

Todd Rapp explaining equipment
Construction Manager Todd Rapp explains the role of the bulk test separator at the Great White well pad.

Permian Facts
and Figures

Located in western Texas and southeastern New Mexico, the Permian Basin covers a region roughly 250 miles wide and 300 miles long. Within the Permian are three large subbasins: the Midland, the Delaware and the Central Basin Platform.

The first commercial well in the Permian was the Santa Rita No. 1, completed in 1923. Several major fields discovered in the 1930s remain in production and are still ranked among the top 20 in the U.S. for remaining proved reserves (Energy Information Administration).

With production of around 2.7 million barrels of oil per day, the Permian accounts for over 20 percent of the country’s crude production and is the second largest oil field in the world, after Saudi Arabia’s legendary Ghawar field (Energy Information Administration, Forbes).
he Permian Basin is estimated by industry experts to still contain recoverable oil and natural gas resources exceeding what has been produced over the last 90 years (Texas Railroad Commission).

In terms of the hydrocarbon-producing zone, the Permian offers formations that are 1,300 to 1,800 feet thick, 12 times the Bakken thickness of 10 to 120 feet. Eagle Ford formations are 150 to 300 feet thick.

In China Draw, located in Texas, the Permian team recently completed its first 80-acre high-low spacing test. At Zia Hills, in New Mexico, the team completed its first 20-foot cluster spacing pilot test.

“To date, the results are encouraging,” Olds said. “Production rates look good, and we’re evaluating full field application.”

Viets photo
Josh Viets, manager, Permian Development

The company is also “coring up” acreage, acquiring adjacent areas to enable longer lateral well development.
“We’ve made a significant effort to core up our land position, allowing us to drill laterals up to 10,000 feet,” Olds said. “This will enable us to lower cost of supply and improve the recovery rate.”

To support development efforts, during the first half of 2018, the team will shoot proprietary seismic in the region and will have the processed data in 2019.

Crissman photo
Seth Crissman, manager, Drilling & Completions GCBU/MCBU

“This is our first time using compressive seismic imaging (CSI) in an unconventional reservoir,” said Viets. “We hope to improve reservoir imaging, as well as have the ability to extract rock properties to better optimize development plans using well stacking in multiple intervals.”

Van Metre photo
Lorena Van Metre, supervisor, Development Engineering

After going down to zero operations during the period of lowest prices, ConocoPhillips’ Permian business unit returned to an active program in February 2017. To leverage spend and protect the company as it reentered the market, the business unit implemented a new contracting strategy.

“Given the popularity of the area, our procurement and supply chain people look for ways to mitigate exposure in the event of price inflation,” said Seth Crissman, manager, Drilling & Completions GCBU/MCBU (Gulf Coast business unit/Mid-Continent business unit). “For example, they worked with Schlumberger to enter into a contract that incentivized and penalized according to performance, and we got constant pricing.”“We were used to working in silos, and we have missed opportunities. In 2016, we decided to find the right balance among functions and come up with a solution that brought the highest value to the asset,” said Lorena Van Metre, supervisor, Development Engineering.

aerial view of Mockingbird
Mockingbird Central Facility under construction

With increased interest in developing the area but limited capital, the team needed a full field development philosophy that aligned subsurface needs with infrastructure while limiting capital spend. The result was an innovative integrated approach.

The result was an infrastructure plan that included transporting production to a central processing facility. This minimizes equipment and processing at each well pad and therefore cost. The first central facility, Mockingbird, is noteworthy for its use of stabilization, a simplified process that heats the oil and removes gas, for a more-balanced output.

In the first quarter of 2018 the team will bring 12 new wells from three quad pads into the new facility, with an additional 16 by the end of the year. 

Neuschafer outdoors
Mike Neuschafer, Operations superintendent

“Currently, every well has its own individual separator, where product is divided into oil, gas and water streams,” said Operations Superintendent Mike Neuschafer. “Now the initial separation will be done on the well pad prior to being delivered to the Mockingbird facility. Equipment at Mockingbird will process water, skim any residual oil and stabilize the oil.”

Ted Westerman, manager, MCBU Capital Projects, noted the project’s successes.

“What Lorena’s team has been able to do through integration with other functions has cut our estimated development costs by 30 percent over two years and lowered our cost of supply by $2/barrel,” Westerman said. “We have proof that integration adds value.”

four team members walking
Members of the Permian construction team survey progress at the Mockingbird Central Facility. From left: Bruce Yates, Construction/Mechanical supervisor; Brandon Davis, specialist, MCBU HSE Construction; Todd Rapp, Construction manager; and Paul King, commissioning lead

Some experts believed there wasn’t much left in the Permian’s conventional reservoirs, but this was not the case for ConocoPhillips. Thanks to various technologies and learnings from unconventional plays, production from conventional reservoirs is up once again.

Perfs and frack graphicIn the Central Basin Platform (CBP), located between the Midland and Delaware basins, the Permian team is using unconventional technology and fracking to improve production from older, conventional reservoirs. The work is producing significant returns. The unconventionals team is applying the same technology in the Northwest Shelf of the New Mexico Yeso formation, also a conventional play.

“Many of these wells have been producing for over 100 years, so all the high-porosity rock has been exploited,” said Viets. “We’ve been able to use unconventional technology such as extended laterals and multistage fracturing to develop poorer-quality rocks in both the CBP and Northwest Shelf.”

Viets explained the process. “We take an existing vertical well and essentially abandon it by setting a plug just above the producing interval. Then we perforate the existing casing and hydraulic fracture those new perforations. From a single data set, we can develop a reservoir simulation model that helps us better understand how a horizontal well would perform in that environment. It’s looking really good.”

Permian Engineering Manager Jon Philley oversees the team responsible for optimizing base production from legacy conventional assets at Waddell, Goldsmith, Southeast New Mexico and Greater West Texas, while supporting production growth in the unconventionals.

three men standing in front of cross section picture
LEFT TO RIGHT: Jon Philley, manager, Permian Engineering; Johnny Golden, manager, MCBU Operations; and Ted Westerman, manager, MCBU Capital Projects
aerial photo of tank battery
War Hammer Central Tank Battery

"A significant part of our optimization is through water and CO2 flood management,” said Philley. “Flood management consists mostly of engineering time and is typically not capital-intensive, so you get a lot of bang for your buck.

“We operate 15 floods, with surface holding tanks and water-handling facilities that clean the produced water and reinject it. Of the four main floods, three are purely water and one is water alternating gas, or WAG. Flooding with water and/or CO2 maximizes recovery from the reservoir.”

A multidisciplinary team made up of Operations, Development and Engineering staff reevaluated high-value floods, leading to new management plans that optimize where and how much water/CO2 is injected to maximize oil production.

Before implementing the flood management plans, the company’s Gandu oil production in the Goldsmith area was on a 15 percent decline curve. Since mid-2016, when it changed its approach, the team has arrested base decline to 10 percent.

“The Permian is one of the brightest jewels in the company’s portfolio,” said Johnny Golden, manager, MCBU Operations, “despite being written off three or four times in the industry’s history. It’s exciting to operate assets that range from the 1930s to some of the company’s newest developments and to use unconventional technology to open new possibilities in the company’s legacy assets.”

One of the Permian team’s 2018 objectives is to continue to evolve the business unit’s water strategy to reduce sourcing and disposal costs associated with field development.

While surface water is not abundant in the basin, wells produce more water than hydrocarbons. In China Draw, there are limited options from a water resource and landowner perspective.

trucks and equipment
Fracking operations at Great White, located near the Mockingbird Central Facility

“Before we can implement any technology involving water, we must figure out how to source it, move it, store it and use it,” said Jeff Murray, water management lead, GCBU/MCBU Completions Engineering. “We’ve worked with landowners to provide near-term services, and we’re planning a treatment strategy with third-party vendors while working with Projects to develop a distribution and storage system to move water throughout China Draw.”

One way to manage produced water is to recycle and reuse it. The Permian team will start using treated produced water for fracking in the first quarter of 2018 and will ramp up to using 90 percent treated produced water in all completions activity in China Draw.

Murray photo
Jeff Murray, water management lead, GCBU/MCBU Completions Engineering

“The other 10 percent will be supplemented with surface water,” Murray said. “Our main challenge is the amount of water that our wells produce. As production increases, we will have more water to deal with.”

To support the produced water reuse strategy, the team has created the Batman Pit, ConocoPhillips’ largest-ever surface water storage pit. Located in central China Draw, the pit stores water diverted through pipelines from the Red Bluff Reservoir. The reservoir, located between China Draw and Zia Hills, is fed by the Pecos River.

“We’re now fracking with surface water,” Murray said. “Moving forward with using treated produced water in 2018, we will use temporary storage provided by a third party. By the third quarter, we will have our own engineered produced water storage ponds. We’re calling the installation Two-Face.”

With Mockingbird coming online in 2018 to handle the new wells, the group will expand the South China Draw and North China Draw water transfer facilities.

“We want to ensure that as much of our produced water as possible is sent by pipe to third-party disposal or to the completions group for treatment and reuse,” said Delaware Operations Superintendent Mike Neuschafer. “There is a huge cost if water is trucked versus piped, up to $200,000 a week. This will only increase as the field grows.”

“The MCBU has a very broad and diverse set of assets,” said Olds. “It’s old and new, and a cash and growth engine for the company. This has been a key year for us to accomplish strategic milestones that have set us up for the growth to come. I can’t wait to see how we perform as we accomplish our growth objectives over the next three years.” 

Permian Basin development driven by integrated study and data analytics

by Josh Viets

ACCURATELY CAPTURING THE ECONOMIC POTENTIAL OF ACREAGE IS CRITICAL to lowering cost of supply and identifying growth opportunities. The Permian Development organization has developed an efficient workflow for mapping the value of acreage built on comprehensive geological characterization, multidisciplinary data integration and advanced data analytics.

Data mining and machine learning are the core engines of this workflow. Reservoir characterization parameters, well spatial data, completion strategies and production measures are integrated into a common platform. A learning model quickly generates type curves from existing wells to establish views of ultimate recovery for wells with limited production histories. Then, multivariable analysis is used to identify performance drivers and quantify the impact of development strategies such as spacing, stacking and completion designs.

Results are tied in with well cost assumptions and development plans to generate a value map which assesses the net present value per acre across the area of interest. This workflow has been adopted across the Delaware and Midland basins.

“The work done by our staff has been invaluable. As we look for opportunities for growth, we know where we want to be within a given basin. I feel like we’re only scratching the surface with this.  We’re in the process of expanding this workflow to our conventional assets as we look for opportunities to increase our horizontal well inventory on the Central Basin Platform.”


El Capitan in the Guadalupe Mountains, just west of the Permian Basin

About the author

Hester headshot

JAN HESTER is assistant editor of spiritnow. A fan of technology, she loves to visit ConocoPhillips sites and write about innovative projects and people. Her background includes public relations, community relations, nonprofit fundraising and the U.S. Foreign Service. Jan adores spicy Asian food, live music, gin, English literature, all kinds of history and animals, especially cats.