Back to basicsDriving base production management in a high well-count onshore environment

By Mohammed Saadat and Thomas Bonny

2

A drive through the small South Texas town of Victoria would convince most skeptics that the North American energy renaissance is well underway. With its large billboards advertising oilfield jobs, sold-out hotels, and bustling truck convoys carrying oilfield equipment, Victoria is representative of many areas across the country where various resource plays are luring both big and small operators. In fact, more than 300 deals totaling upward of $60 billion USD have been announced in North American onshore plays in just the last six months. These hives of E&P activity promise growth and monetary success; yet underlying operational inefficiencies threaten market performance, especially in a cost-inflationary or hostile price environment. In fact, operating margins would depict an unfavorable trend had it not been for encouraging energy prices in 2013 (see figure 1, page 3). Further, considering the recent significant drop in oil prices, pressure on operating margins may only get worse.

As a result, onshore operators increasingly are coming under market scrutiny and feeling the pressure to deliver profitable production. Their traditional responses have been to drill more wells faster and cheaper and to cut costs, all without understanding the implication of these actions on the unit cost of production.

The recent split of BP North America into onshore and offshore businesses highlights a growing trend toward a fundamentally different way of operating high wellcount onshore operations, especially in the unconventional arena. What makes the difference is a more integrated approach in the management of both capital campaigns and production operations. However, this approach has not been a priority, which has resulted in leaving behind significant untapped value, particularly in the development phase of resource plays. In fact, different operators in the same field may use very different production management practices, and their production values will vary considerably (see figure 2, page 4).

ILLUSTRATION BY PHIL BLISS

3

More of the same is not the answerOnshore operations have changed significantly over the last decade, and the catalyst for onshore production growth is high wellcount operations, typified by the US unconventional market. The scale and dynamics of the unconventional market present a variety of challenges as compared with conventional plays. For example, the Ghawar Field, Saudi Arabias largest conventional oil field, is more than 60 years old and delivers five times the oil production with half the well count in 2% of the acreage of the Bakken basin, one of the top unconventional plays in the US.

These high wellcount plays closely resemble manufacturing facilities, characterized by mass production, tight margins, and under dynamic triggers such as changing demand and regulatory oversight. This fast-paced environment requires frequent reallocation of rigs across the portfolio of assets to drive production growth, and most current operating models are simply not suited to manage this.

To be successful in this market, operators will need to overcome the following key challenges.

1. Experience trumps data-driven decision making. In the early days of onshore drilling, a common practice among oilfield personnel was to take a hands-on approach to field management by physically monitoring the performance of the well. In fact, field operators were not satisfied unless they had been onsite at each well location. Because of the large scattering of wells, ever-increasing regulatory oversight, and loss of experienced personnel, neither this approach nor decision making based on intuition rather than data will prove sustainable. The absence of data-driven decisions with high wellcount plays can lead to an ineffective prioritization of activities, which in turn, increases response time to well failures and thus production downtime.

$49.36 $45.60 $49.91

While unit operating margin has remainedrelatively flat across unconventional operators...

Weighted average book price

...normalizing market prices indicates that infact operating margins are down.

Actual weighted average operating marginPeer group2, $/BOE, 2010-2013

Normalized weighted average operating marginPeer group2, $/BOE, 2010-2013

2011

$36.87

2012

$32.78

2013

$37.24

+1%

Favorable market conditions have helped support operating margin per BOE

2011

$36.87

2012

$32.78

2013

$32.931

-11%

Had book prices remained constant in 2013 relative to 2012, unit margins would have eroded

Margin squeeze driven by increased operating costs

1 Price held constant over time at 2012 book price for 2013 for each operator to adjust for YoY oil and gas market prices increase.2 Unconventional operators in study include Apache, Anadarko, Devon, EOG, Marathon, Hess, Whiting, Occidental, Continental, Noble, Cimarex, Chesapeake, Pioneer

FIGURE 1: OPERATING MARGINS FOR SELECT US ONSHORE PLAYERSSOURCE: ACCENTURE STRATEGY ENERGY (FORMERLY SBC)

4

2. Cultural inertia. In the days of low-count, slowly declining wells, field operations had a certain predictable rhythm. Activities were focused on maintaining a given level of production and performing physical inspections of well sites to ensure environmental compliance. The unconventional business has upended this cadence. With thousands of wells and declining production rates ranging from 60% to 70% in the first year, activities are now progressing at a faster pace. The inability to adapt has led to inefficient resource utilization. For example, well site operators are now overseeing twice or triple the number of wells as compared with pre-unconventional days. In many cases, well site visits are not prioritized, and high-value wells are often overlooked or delayed. A similar approach is often seen with workover rigs where operators allocate time to the loudest field supervisor rather than to the well site where the most value can be realized.

3. Narrow focus on overall cost versus unit cost. The traditional explore-by-the-bit approach to resource development worked well in mature plays where surface uncertainties were clearer. As operators moved to frontier plays (e.g., Mississippian Lime, Niobrara), it was no longer viable to base development decisions on expected production and drilling and completion costs. A broader view of uncertaintiessuch as takeaway capacity, infrastructure, and water managementis now required to understand the true life cycle economics of the play. For example, the Mississippian Lime tight oil play is known for extremely high water cuts that require investment in disposal infrastructure, which impacts the economic viability of the asset. Additionally, a singular focus on lowering costs can lead to shortsighted operational decisions such as less investment in automation and processes, which compromises the reaction time to production failures.

FIGURE 2: BAKKEN BASIN PEER GROUP DECLINE CURVES

There is considerable variation in the decline curves of various operators within the same basin, suggesting the use of varying production management practices and illustrating how they can impact production values.

SOURCES: IHS SUPPLY ANALYITICS 2014 BAKKEN; ACCENTURE STRATEGY ENERGY (FORMERLY SBC)

600

800

700

300

500

400

0

200

100

BOEP

D

0 6 12 18 24 30 36

TIME (MONTHS)

Potentially available uplift over 30 months of base production:

~32,000 BOE between Best-in-Classoperator and Operator 2

~12,000 BOE for Operator 2 consideringoptimum base production management

Best-in-Class

Operator 1

Operator 2

Operator 2 optimum baseproduction management

Bakken Peer Group Decline CurvesBOEPD vs. Months

5

4. Organizational silos. Onshore conventional operations in North America, usually characterized by low well count and vertical wells, are often suited to a more functionally focused structure. Petrotechnical teams focus on the upfront de-risking of the asset while the execution team takes over field development after the final investment decision (FID). The execution team often makes incremental tweaks such as completion or facility design changes with limited or as-needed interaction with the petrotechnical teams. Unconventional resource development requires a more iterative approach to accelerate commerciality of resource plays in the early pilot phases and later to drive execution efficiency in the development phase. Assumptions made at the start of the de-risking phase rarely stay constant. In fact, in many resource plays, the development and pilot phases often take place concurrently, and the results from one feed the other. Multiple investment choices, therefore, need to be made along the field life cycle as technical, commercial, and surface uncertainties become known. Considering the sheer volume of wells in an unconventional play, unit costs cannot be improved unless execution teams consistently loop in other functions across the entire value chain to continuously incorporate new learning that improves play development. For example, a decision about the size of the drilling hole can significantly limit artificial lift options during the field development phase, which can negatively impact delivery potential of the field. This decision can have a material impact when managing thousands of wells versus less than 100 wells.

Operators need a new toolkit for onshore operationsTo address these challenges, especially as West Texas Intermediate (WTI) oil prices recent