HeatH Williams, RogeR Keese, sylvaine le Roy-Delage, Justin Roye, DonalD leacH, PeteR RottleR anD olivieR PoRcHeRie, scHlumbeRgeR, usa,

exPlain HoW a neW flexible exPanDing cement system is being useD to guaRD against PooR cement sHeatH integRity anD HelP solve

sustaineD casing PRessuRe PRoblems in tHe maRcellus Play.

flexibletecHnology

Expectations are high in the Marcellus Shale. Operators expect prolific yields of gas and legislators expect strict environmental compliance with cementing policies in a trend that stretches across the state of Pennsylvania. Operational challenges (mud removal, cementing and completion) abound; the greatest issue, sustained casing pressure (SCP), can surface before and after completion.

A flexible, expanding cement system (FECS) with fit-for-purpose mechanical properties to work in the Marcellus Shale and combat SCP has been developed.

Four wells in the Northern Marcellus were selected for initial field testing using the FECS technology. The system was used on two wells on both the intermediate and production casings and it was used on two other wells on the production string. All six jobs were successfully performed without incident and based on mechanical property analysis, the FECS technology was able to survive anticipated stimulation pressures when the conventional cement system did not.

OILFIELD TECHNOLOGYReprinted from July 2012

OILFIELD TECHNOLOGYReprinted from July 2012

SCP: An enemy in the Marcellus ShaleOver the life of a production well, the wellbore experiences a variety of stressful scenarios. Drilling, stimulation, changes in pressure and temperature, and natural tectonic activity are all stresses that may be detrimental to the casing-cement sheath-formation system. Stimulation is particularly detrimental to cement sheath integrity, with casing pressures exceeding 8000 psi. This pressure-induced casing expansion can place compression and tensile stresses

on the sheath, inducing cracking and debonding, as well as compromising zonal isolation.

Because of stimulation-induced stresses or other possible causes, Marcellus production wells are experiencing SCP. SCP is caused by hydrocarbon fluid migration (typically gas) from the formation to the surface through communication pathways in the annulus. In the Marcellus, the communication can come from the target formation or from shallower gas-bearing zones. This pathway potentially allows interzonal communication from a hydrocarbon zone to environmentally sensitive zones or to the wellhead and potentially the atmosphere.

Depending on the degree of communication, the pressure build-up rate varies from well to well, and is usually bled off when the wellhead pressure rises to unsafe levels. However, if communication is present, the pressure will rise again, and the pressure bleed-off procedure is repeated. For SCP wells, constant monitoring is necessary. While the industry has implemented several measures to reduce the likelihood of SCP, approximately 25% of wells located in the Marcellus shale still produce measurable annular surface gas.

Some of the preventive measures that the industry has introduced include improved mud removal and cementing practices, including improved centralisation and fluid hierarchical design and chemical and mechanical SCP barriers. With a more challenging regulatory environment, a collaborative effort between the operators and service company was undertaken to determine necessary cement sheath properties to prevent early gas influx into the annulus and also sufficient mechanical properties to prevent potential damage from excessive stimulation-related stresses acting on the cement sheath for wells located in the Marcellus Shale.

Importance of the MarcellusA shale play is an unconventional underground geologic formation where accumulations of natural gas, oil, or coal may be found. Previously thought of as uneconomical to produce, recent advances in horizontal drilling and hydraulic fracturing techniques have made these plays both accessible and profitable.

Figure 3. Tangential stress did not exceed FECS tensile strength in this summary of the FECS system.

Figure 2. Tangential stress exceeded tensile strength at 430 psi and 2.75 in. from the well axis at the cement-casing boundary in this summary for the conventional cement system.

Figure 1. Following adjustment of several properties of the prototype FECS system in the software, a combination of cement sheath mechanical properties was found to ensure zonal isolation in the studied wells.

OILFIELD TECHNOLOGYReprinted from July 2012

The Marcellus Shale is a geologic formation of sedimentary rock that contains natural gas. Named for a distinctive outcrop near the village of Marcellus, New York in the US, the Marcellus play extends throughout much of the Appalachian Basin. The shale contains largely untapped natural gas reserves, and its proximity to the high-demand markets along the East Coast of the US makes it an attractive target for energy development.

The Marcellus Shale play is the largest shale play in the US by land area and extends across 95 000 square miles with the majority

Figure 4. Linear expansion as a function of chemical expansion additive.

Figure 5. Improved cement coverage is indicated deeper into the production section of this well.

of Marcellus Shale land area in six states (New York, Pennsylvania, West Virginia, Ohio, Virginia, Maryland). Production from this play is primarily from depths between 4500 and 8500 ft with 50 to 150 ft net pay thickness and 1500 trillion ft3 of original gas in place with 260 trillion ft3 of technically recoverable gas.

Natural gas drilling in the Marcellus Shale became economically feasible for development when advanced drilling and completion techniques, such as horizontal drilling coupled with hydraulic fracturing, were developed. Typical wells in the Marcellus Shale

have an average depth of approximately 5300 ft below the surface.

Between 2009 and 2011 rig counts have grown in this play by 300% and forecasts estimate that 30 000 new wells will be drilled between 2011 and 2020. More than 1900 wells were drilled in the Marcellus Shale during 2011, according to the US Department of Environmental Protection. Bottomhole static temperature is upwards of 140 F with bottomhole pressure up to 6000 psi and total vertical depth from 4000 to 7500 ft.

FECS applied to mitigate SCPBuilt on principles that demonstrate the benefits of flexible, expanding technology, the new FECS slurry system density ranges from 11.0 to 15.5 lbs/gal. and up to 60% solid volume fraction of the total slurry volume. By enabling the set cement to conform to the changes that occur during drilling, production, and abandonment cycles of a well, FECS technology can offer lifelong isolation.

The system exhibits a bulk volumetric increase after setting and is flexible. The expansion aids in the prevention of unwanted gas migration. Control of the cement reaction kinetics is achieved using dry or liquid additives, and as a result, can control slurry or set cement properties over a range of temperatures and pressures.

Introduction of FECS in the MarcellusAfter the conventional cement failed in cement mechanical property simulation, and since well geometry and formation properties were fixed, the main remedy to achieve zonal isolation during stimulation operations in the Marcellus was to adjust the mechanical properties of the cement sheath. After adjusting several properties of the prototype cement system in the software, a combination of cement sheath mechanical properties was found to ensure zonal isolation (Figure 1). The prototype system maintained matrix integrity and zonal isolation.

Based on FECS mechanical property analysis in an identical annular geometry and dynamic simulation schedule to the conventional cement example summarised in Figure 2, the predicted cement sheath

OILFIELD TECHNOLOGYReprinted from July 2012

compressive strength (1600 psi) exceeded the simulated Mohr-Coulomb stress (800 psi) acting on the cement sheath and the predicted cement tensile strength (200 psi, or 13% of the cement sheath compressive strength) exceeded the simulated tensile stress (197 psi) (Figure 3). No microannulus was predicted by the model.

Laboratory testing and validation of FECS Before introduction of FECS in the Marcellus Shale trend, short term gelation/setting properties of the slurry were evaluated. FECS expansion and mechanical properties were also optimised and evaluated. Even with reduced cement content, static gel strength development passed or exceeded industry requirements.

Linear expansion measurements were performed with different concentrations of chemical expansion additive in an annular expansion ring according to industry-accepted guidelines. Linear expansion of FECS at 150 F curing temperature as a function of expanding additive concentration is summarised in Figure 4. With an increase to 4% BWOB expanding additive, maximum linear expansion increased to approximately 0.3%.

FECS cement system mechanical properties were tested at several densities and temperatures and testing results indicated that FECS flexibility can be finely tuned depending on well requirements (Table 1). Compressive strength and Youngs modulus measurements for a 14.0 lb/gal. system ranged from 1.7 to 2.8 kpsi and 500 to 650 kpsi, respectively, with a temperature increase from 100 to 200 F. With these properties, FECS demonstrated greater flexibility while still maintaining relatively high compressive strength. The greater flexibility reduced the tensile stresses imparted on the cement sheath during stimulation operations, and increased the probability of the sheath maintaining long term zonal isolation.

Application of FECSA typical northern Marcellus well is constructed of a 4-casing-string design that includes:

x 20 in. conductor casing at approximately 60 ft.

x 13 3/8 in. surface casing at 350 800 ft.

x 9 5/8 in. intermediate casing at 1000 3500 ft.

x 5 in. production casing at 10 000 - 15 000 ft.

The well in which FECS was applied had the following configuration:

x 20 in. conductor casing at approximately 60 ft.

x 13 3/8 in. surface casing at 640 ft.

x 9 5/8 in. intermediate casing at 2477 ft.

x 5 in. production casing at 11 850 ft (approximately 6870 ft TVD).

The production casing used 28 solid-body rigid centralisers, with one centraliser run every three joints from 3510 ft to 6897 ft MD (about 30 into the curve). The production casing was drilled with an air/mist combination down to kickoff point, at which point the hole was loaded with a 12.5 lbs/gal. synthetic-based mud (SBM).

Table 1. Summary of mechanical properties for FECS over a 13 - 15 lbs/gal. density range

Density, lbs/gal. 13.0 13.5 14.0 14.0 14.0 14.0 14.5 15.0 15.5

Temperature, F 150 150 100 140 150 200 150 150 150

Compressive strength, kpsi 1.93 2.06 1.68 1.60 1.42 2.78 1.52 2.12 1.75

Youngs modulus, kpsi 449.6 632.6 507.6 450.0 652.7 551.1 652.7 739.7 870.2

Poissons ratio 0.23 0.19 0.21 n/a 0.18 0.16 0.16 0.16 0.18

Because the directional driller experienced some difficulties during the final phases of drilling, no wiper trips were made prior to running casing.

Casing was successfully run and the well was circulated at 350 gal./min. for three hours prior to cement job placement. To further ensure casing-to-cement and cement-to-formation bonding, a weighted spacer with appropriate surfactant

package/concentration and friction hierarchy was designed for optimal SBM removal from the formation and casing during cement placement. The fluid sequence was:

x 60 bbl. weighted spacer with validated surfactant package.

x 155.1 bbl. FECS lead slurry.

x 240.7 bbl. conventional tail slurry.

x 258.8 bbl. water displacement.

The FECS slurry was used as a lead slurry and was placed from 6580 ft (build section leading eventually to horizontal interval) to the predicted top of cement of 3480 ft (approximately 1000 ft below the intermediate shoe). The tail slurry was a conventional slurry placed from the production casing shoe, throughout the entire horizontal interval, and up to the bottom of the lead slurry (6580 ft in the curve). A third-party double-plug cement head was used that had the capability to reciprocate and rotate throughout the job to provide better fluid placement in the annulus. The hollow bottom plug was launched ahead of the weighted spacer and the solid top plug was launched between the tail cement and the water displacement.

Successful cementation using FECS technology The job was executed successfully and the design objectives were achieved. Following completion of the production job, a cement bond log (CBL) was performed for each casing string. The CBL was valuable in that it measured the presence or absence of dry microannulus but had limited capabilities with wet annulus detection. Since the production job called for displacement with completion fluid (brine), dry microannulus, if present, was primarily due to poor mud removal/cement practices and/or cement bulk shrinkage. After cementation of the production string, the CBL indicated good cement coverage through much of the FECS-cemented interval (Figure 5).

Fair to good cement coverage was reported from 3480 ft (predicted TOC) to 4050 ft. Good to excellent cement coverage was estimated from 4050 ft down to the bottom of FECS placement. Expansion properties of the FECS cement system helped to reduce the microannulus and improve cement bonding, which was supported by CBL results. The production CBL was performed approximately one week after cement placement down to 30 into the build section. Based on laboratory evaluation of the expansion properties, 0.2 0.3% bulk expansion could be expected by the FECS prior to CBL measurement.

During stimulation of the studied wells, wellbore pressures exceeded 9000 psi. No SCP has been observed in the Marcellus Shale wells cemented with FECS technology more than a year ago. The FECS technology is expected to be equally beneficial to industry projects in other shale plays. O T