Summer 2009
Increasing Production From
the Haynesville Shale

Ever since the initial discoveries were made in the Haynesville Shale in early 2008, operators have been improving drilling and completion approaches in this emerging play. The Haynesville is now recognized as one of the most promising gas plays in North America with enormous potential. In an effort to optimize production, operators are working to better understand the Haynesville’s reservoir conditions, and in particular, how to optimize fracturing treatments. Important discoveries are having a significant impact on proppant selection and subsequent fracture treatment results in the Haynesville Shale.

Haynesville Background
True vertical well depths (TVD) in the Haynesville Shale typically range from 10,000 to 13,000 ft (3,048 – 3,962 m) with closure stress ranges from 9,000 to 12,000 psi (62 – 83 MPa) and bottom-hole temperatures that reach 300°F (149°C) or more. This makes the Haynesville one of the deepest shale plays in North America with HPHT (high pressure, high temperature) well conditions. Currently, approximately 85% of the wells drilled are horizontal while only 15% are vertical. The vertical wells are typically drilled to locate the play borders. Most of these vertical wells are also drilled and completed for formation evaluation purposes. Once operators have evaluated the reservoir and formation properties with the vertical well(s), they move to horizontal well completions. This evaluation method is used to ensure that horizontal wells are drilled in the most productive areas as horizontals are usually about three times more costly than vertical wells.

According to industry experts, the Haynesville Shale could develop into one of the largest natural gas plays in North America. Due to its favorable economics, the play’s potential will likely be a major factor in many operators’ exploration and production strategies. This is partially due to the comparatively low finding and development costs in the Haynesville. To effectively support the Haynesville operators, many fracturing service companies are investing heavily to create the necessary infrastructure in the East Texas and North Louisiana areas. This includes moving existing equipment and personnel from other plays to the Haynesville as activity increases.

For active operators in the Haynesville, maintaining high well production is becoming a major focus. The current best practice is to complete a 3,000 ft (914 m) lateral section with 10 to 12 frac stages separated approximately 300 feet (91 m) apart with perforation clusters every 50 to 60 feet (15 – 18 m). Large amounts of natural gas must be produced in a short time by a Haynesville well to be considered economical since drilling and completion costs are relatively high. Many of these wells are producing at an initial production (IP) rate of up to 20 million cubic ft (MMcfd) or more, and recovering up to one billion cubic ft (Bcf) of gas rather quickly; however, many wells experience rapid production decline curves. Some operators have reported between five and seven Bcf estimated ultimate recovery (EUR) per horizontal well. The Haynesville’s higher reservoir pressure has allowed wells to produce at far higher rates compared to other shale plays in North America. Payouts in the Haynesville are often measured in months, compared to years in other plays.

Fracturing Design
Improving the fracturing treatment results in the Haynesville is a continuous focus. The prevailing treatment design is a slickwater with 10 to 15 stages per lateral pumped at rates up to 80 BPM averaging 200,000 to 300,000 lbs (90,720 – 136,080 kg) of small mesh proppant in 10,000 to 12,000 BBLS (1,192 – 1,430 kl) of water per stage. “Hybrid” slickwater variations are also pumped which include crosslinked gels and larger mesh proppant tail-ins. It has generally been found that more frac stages and higher proppant volumes lead to higher production.

Haynesville Proppant Usage
Due to the reservoir and formation conditions, as well the prevalence of waterfrac designs, 40/70 mesh resin coated sands as well as 40/80 mesh uncoated lightweight ceramics have been predominantly utilized. Some recent designs have led to larger mesh tail-in proppants to ensure higher near-wellbore fracture flow capacity, especially in horizontals where flow convergence at the wellbore is an issue.

Operators are discovering that certain proppants are more effective in the Haynesville. Several operators have recently made the decision to switch from uncoated ceramics to resin coated sands due to the favorable economics of the lower cost resin coated sands. Some limited amounts of uncoated frac sand are being pumped due to the current economic environment, but this proppant usually results in lower initial production rates and rapidly declining production curves.

At a recent forum in Texas, operators provided details on how their wells were performing in the Haynesville Shale. The Developing Unconventional Gas (DUG) conference in Ft. Worth, TX included presentations by several executives that discussed how their wells fractured with uncoated ceramics were essentially producing the same as those fractured with resin coated sands. They also stated that they were switching to resin coated proppants for the additional benefits they provide. One of the recurring points made was that they were obtaining the same, if not better, results with resin coated sands as compared to uncoated ceramics.

Haynesville Proppant Selection Challenges
The Haynesville’s HPHT well conditions along with its softer formation rock properties present identifiable challenges to real-world, downhole proppant performance. Besides the typical concerns of waterfrac proppant selection (visit waterfrac.com for more information) relating to proppant fines generation and migration; proppant pack cyclic stress changes during the well’s life; and proppant flowback in the horizontal laterals, additional unique well conditions in the Haynesville Shale have surfaced that effect proppant performance downhole. Fracturing engineers must now consider downhole proppant embedment and scaling/corrosion in their Haynesville designs. These aspects of the Haynesville further reduce fracture flow capacity which can lead to significantly poorer than expected fracture treatment results.

Proppant scaling/corrosion is a geochemical reaction that occurs between the proppant pack and formation in a wet, hot downhole fracture environment. While this reaction normally happens slowly in shallower shale formations, it accelerates quickly under the higher pressures and temperatures found downhole in the Haynesville. The result is a severe loss of proppant pack porosity and permeability as fines and debris are created in the proppant pack (as shown in the photo*). Uncoated ceramics can lose up to 90% proppant pack permeability in only a few days*. Resin coated proppants drastically reduce the impacts of proppant scaling, resulting in improved fracture flow capacity. As indicated in SPE 118175, the author states that field studies showed that resin coating the proppant had a significant impact on the long-term productivity of HPHT fractured wells.

Proppant embedment is another issue prevalent in the Haynesville due to its soft rock formation properties. Young’s modulus in the Hayneville has been measured between 500,000 to 3 million. Hard, brittle proppants such as uncoated ceramics deeply embed into softer formations such as the Haynesville due to the increased single point loading between the proppant grain and the soft fracture face. This leads to reduced fracture width and lower fracture flow capacity.

Curable resin coated proppants minimize embedment by redistributing stress loading on each individual grain. This is achieved through the grain-to-grain bonding that occurs which forms a strong proppant pack lattice network.

Effective vs. Reference Conductivity
Proppant pack conductivity must also be carefully considered when choosing fracturing proppants. Effective conductivity is utilized as a more accurate measurement of proppant performance downhole to assist fracturing engineers with proppant selection. Effective conductivity derived from the Wet, Hot Crush Test, takes into account the impact of proppant fines on proppant pack conductivity using the Coulter and Wells** method. Tests compared Prime Plus™ 40/70 (0.5% fines) to a lightweight ceramic (8.2% fines) and raw frac sand (23.9% fines). The test results clearly demonstrate the superiority of Prime Plus under more realistc downhole conditions as found in the Haynesville (as shown in the chart and photos).

Haynesville Proppants

The ideal proppant for the Haynesville should have the following characteristics:

  • Provide ease of placement with desired specific gravity and frac fluids for cost effective designs
  • Be strong enough to withstand closure stress and inhibit fines
  • Have curable characteristics to address a) embedment tendencies in soft shales, b) proppant pack rearrangement, and c) cyclic stress from production changes
    during the life of a well
  • Eliminate proppant scaling tendencies that result in rapid and severe loss of production
  • Minimize proppant flowback during the production life of the well to address production loss and horizontal wellbore cleanout costs

Prime Plus is the only premium, curable 40/70 mesh resin coated proppant offered in North America. Since its introduction in late 2006, Prime Plus has been utilized in thousands of wells in every major waterfrac basin in the United States and Canada. It is recommended for applications with closure stresses ranging from 6,000 to 10,000 psi (41 – 69 MPa). Prime Plus 40/70 is the preferred fracturing proppant for the Haynesville Shale due to its unique benefits. It has demonstrated its ability to provide improved fracturing treatment results and a superior economic benefit when compared to uncoated ceramics and frac sand.

Based on the success of Prime Plus 40/70, Hexion is introducing Prime Plus 30/50. This new proppant has higher conductivity and is an excellent tail-in option for Haynesville Shale fracture treatments.

XRT Gold H™ is a -16+40 mesh curable proppant specifically designed for moderate closure stress ranges in horizontal wells. These proppants use Hexionís patented XRT™ (eXtreme Resin Technology) system to encase specially graded frac sand that yields a proppant with very low crush and high fracture flow capacity. XRT Gold H provides strong bonding in the fracture, and with its unique Stress Bond™ (SB) technology, wellbore consolidation concern is eliminated, facilitating ease of removal if necessary. XRT Gold H provides outstanding proppant flowback control, proppant cyclic stress resistance, and exceptional tail-in, near-wellbore fracture flow capacity.

Hexion InfrastructureHexion’s Infrastructure
Hexion’s North America infrastructure allows us to efficiently service the Haynesville Shale’s ever-increasing proppant demands. Our manufacturing and transportation grid in North America is well designed to provide high volumes of quality resin coated proppant to fulfill the largest fracturing programs in the Haynesville. While other proppant suppliers often have to transport proppant in from outlying areas for the larger frac jobs, Hexion’s high capacity transloads in the area allow us to have more proppant readily available for any size frac treatment.

Hexion is continuing to expand its operations to service our customers operating in the Haynesville Shale. With expansions to our plants and transloads, we are set to bring in even more product to better supply this market. We are moving forward with all our expansion plans during the downturn to ensure that we have sufficient supply available when the economy inevitably picks up and activity increases. The Haynesville Shale is proving to be one of the most valuable resource plays in North America. Hexion’s innovative technology and infrastructure is well positioned to serve Haynesville operators and service companies to help you Get the Results You ExpectSM.


*Photo and statistics courtesy of SPE 118175 (Prevention of Geochemical Scaling in Hydraulically Created Fractures – Laboratory and Field Studies, P. Nguyen, J. Weaver, R. Rickman, Halliburton, 2008).
**Coulter & Wells, Journal of Petroleum Technology, 1972.


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