Zonal Isolation in Geothermal Wells - Stanford Earth - Stanford University

PROCEEDINGS, Fortieth Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, January 26-28, 2015 SGP-TR-204

Zonal Isolation in Geothermal Wells Arash Shadravan, Baker Hughes, Mohammadreza Ghasemi and Mehrdad Alfi, Texas A&M University 11211 FM 2920 Road, Tomball, Texas, 77375 [email protected], [email protected], [email protected]

Keywords: Zonal Isolation, Well Integrity, Geothermal Cement, Lost Circulation and Corrosion. ABSTRACT Well integrity has had an utmost importance for oil and gas wells and many studies have been conducted to improve zonal isolation. However, few papers comprehensively investigated the elements conducive to well integrity and zonal isolation in geothermal wells. Geothermal energy is generated in over 20 countries and the United States is the world's largest producer. This clean source of energy has been benefiting the nation from the operational geothermal projects in California, Nevada, Alaska and Hawaii as well as around the world. Geothermal energy has been considered as one of the main clean resources of energy which its fields produce only about onesixth of the carbon dioxide that a relatively clean natural-gas-fueled power plant produces. The objective of this paper is to investigate the practical solutions for effective zonal isolation in geothermal wells. Viable solutions for extreme high temperatures, lost circulation, CO2 attack, in addition to cement and casing integrity are defined and applied. The case studies reviewed demonstrates the crucial role of these critical elements for safe and environmentally friendly geothermal wells. This analysis helps providing proper wellbore integrity for safe geothermal operation which doubtlessly is the most critical factor towards providing good zonal isolation. 1. INTRODUCTION The growth in global geothermal power market created opportunities for energy demand around the globe. As of August 2013, the global geothermal industry reached 11,770 MW of installed geothermal capacity. Currently there are 11,770 MW of planned capacity additions of geothermal power in the early stages of development or under construction in 70 countries and territories around the world. Additionally, developers are actively engaged with 27 gigawatts of geothermal resource globally. Figure 1 shows the geothermal resources in the United Stated which are identified for hydrothermal sites and deep Enhanced Geothermal systems (ESG). Unlike most of the oil and gas wells, geothermal operations face with extreme high temperatures. Utilizing downhole tools and the selection of cement, drilling fluid, spacer and casings must consider such thresholds. In the enhanced geothermal systems, water is pumped underground through piping to maintain the steam production. This carbon-neutral, inexhaustible energy source could meet 15 percent of America's electricity needs by 2030. Safe geothermal operations provide clean energy 24 hours a day, 365 days a year. Therefore, there has been an evolving progression in high-temperature instrumentations and seals, logging, casing thermal expansion, drilling fluids, drill bits and increased rate of penetration, lost circulation prevention and directional drilling in Geothermal wells. This paper identifies the main zonal isolation challenges and presents the fit to purpose solutions.

Figure 1: US geothermal resources map and their thermal gradient. 2. ZONAL ISOLATION Each reservoir zones should be isolated to control flow. Zonal isolation needs to be integrated into drilling and cementing planning and development strategies in a way that wellbore integrity is ensured and the fracture conductivity in either production or injection is not compromised. Walters et al. (2012) listed 10 options to achieve zonal isolation in geothermal wells: 1) 2) 3) 4)

Drill to the total depth and use an open hole packer string Cemented Liner Sanded Liner Cemented liner with stage cementing collars 1

Shadravan, Ghasemi and Alfi 5) 6) 7) 8) 9) 10)

Liner with external casing packers Liner with swellable packers Plug and go: drilling to each fracture and stimulate using solid expandables Plug and go: drilling to each fracture and stimulate using liner and swell packers Access fracture zones by multilateral wellbores Access fracture zones by multiple sidetracks

Available current packer technologies assisting zonal isolation are: 1)

2)

Open Hole: a. External inflatable casing packers (ECPs) (rated to 600°F) b. Multiple frac system using open hole packer and pressure actuating sleeve (rated to 338°F) Cased Hole a. High temperature packer systems (rated to 600°F)

Cement systems must be effectively designed to improve zonal isolation. They should contain flexible additives which can increase the elasticity and decrease the compressibility and permeability of cement. Le Roy et al. (2010) investigated cement systems composed of the lime-magnesia-silica-water and lime-alumina-silica-water systems (45-65%) and found out the magnesium compositions were found to be stable. The bottomhole temperature of geothermal wells can be as high as 700°F. The ultimate desired compressive strength was 2,000 to 3,000 psi, accepted by most of the operators for geothermal operations. While the cement has to have a certain thickening time for placement, it was required to have 500 psi within 24 hours and 1,000 psi after seven days. The maximum preferred permeability for slurries above and equal to 15 ppg was 0.1md and for slurries below 15 ppg was 0.25md. 100 psi was determined as the minimum requirement of cement-casing bond strength. The expansion of 0.2 to 0.4 percent was considered optimum (Nelson, Eilers, & Spangle, 1981). It is also recommended to add silica to cement formulations designed for high temperatures in order to maintain the required compressive strength and permeability. Slurry design is affected by well depth, bottom hole temperature (static and circulating) type of drilling fluid, slurry density, pumping time, quality of mixed water, fluid loss control, flow regime, mechanical properties, free water and quality of cement. Most geothermal wells are not cemented under geothermal conditions but circulation of drilling fluids in the well for several hours reduce well temperature. Experimental results indicated that the thermal and stress induced affect the integrity of cement sheath. Figure 2 demonstrates different well design concepts for deep geothermal wells. It is necessary in geothermal wells to have the casings fully cemented to minimize the casing expansion especially during steam production and prevent buckling. Casing is selected based on the subsurface characteristics of the well, including the diameter of the well and the pressures and temperatures the well is expected to experience over its full producing lifetime. However, casing must be properly run into the borehole to ensure it meets all of its specified ratings. When the casing is in place, proper well cementing is essential to protect subsurface aquifers and to prevent gas migration for the full expected lifetime of the well. It is also relevant to maintain a good rheological and friction pressure hierarchy when pumping the mud, spacer and cement. This would tremendously help with minimizing any fluid intermixing.

Figure 2: Various Geothermal Well Designs After cement placement, it is important to predict the long term cement integrity with computer models. Downhole conditions, cement and formation mechanical and thermal properties would be inputted in computer models to predict the success of cement jobs. Figure 3 shows an example of such analysis in which the mechanical properties of cement sheath which passed the radial stresses but exceeded the tangential threshold and consequently failed in tension. Such model would help engineers to redesign the cement slurries and predict the assurance of the integrity of the cement sheath. 2

Shadravan, Ghasemi and Alfi

Figure 3: Cement Integrity Simulator

Table 1 shows the consequences of poor zonal isolation before and at the time of production. This could be detrimental to the environment and the integrity of geothermal wells. Table 1: Wellbore integrity: what can go wrong? Formation damage during drilling (caving) Casing decentralization (incomplete cementing) Inadequate drilling mud removal Pre-Production

Incomplete cement placement Inadequate formation-cement/cement-casing bond Cement shrinkage Contamination of cement by mud or formation fluids Micro-annulus at casing-cement interface

Production

Mechanical Stress/Strain

Disruption of formation cement bond Fracture formation within cement

One of the common problems occurring during primary cementing is the invasion of gas into the cement during the setting process. As cement gels, it loses the ability to transmit hydrostatic pressure. During this period, fluids (water and/or gas) can invade the cement and form channels. This flow of formation fluids can be from the pay zone to the surface or can be cross-flow between zones of differing pressure. This type of short term fluid migration problem often leads to long term zonal isolation problems and sustained casing pressure. Changes in pressure and temperature or exposure to extreme high temperature can cause cement to debond from the casing. Portland cement is a brittle material and susceptible to cracking when exposed to thermally induced or pressure induced tensile loads. Long-term gas migration occurs due to cracks in the cement sheath, microannuli, or channels in the set cement. Numerous factors during drilling operation such as poor mud removal, poor casing centralization, excessive free water and cement sheath shrinkage directly affect the long term well integrity. After drilling and reaching the total depth, corrosion, depletion, and workover or other remedial treatments considerably affect the integrity of cement sheath. In addition, extreme high pressure conditions impose a huge risk on effective zonal isolation in geothermal wells if the cement slurry is not properly designed. Cement sheath failures occur as a result of temperatureinduced stresses. Flexible and expanding cements with enhanced mechanical properties have been introduced. Such flexible cements provide controlled expansion and have high tensile strength and improved young modulus. Resistance to corrosive gases such as CO2 is very important in order to reduce long term gas migration. Self-healing cement (SHC) provides long-term zonal isolation with a sealing material that has an intrinsic self-healing property. Hydrocarbons activate the self-healing material whenever the integrity of the cement sheath is compromised (e.g., cracks and microannuli) and would then efficiently seal the leak path by swelling when in contact with hydrocarbons. Engineering analysis must be utilized in order to assess stresses on the cement sheath during various well operations. Such a study keeps the cement sheath below its endurance limit and improves cement sheath integrity during the well life. With the current momentum of tapping the new geothermal resources, cement integrity analysis is a key to operate securely.

3

Shadravan, Ghasemi and Alfi 3. LOST CIRCULATION Lost circulation treatment can take up to 15% of the well cost and there has been some geothermal wells that were abandoned due to massive lost circulation and complete loss of returns at pumping rate of hundreds of barrels per hour (Finger & Blankenship, 2010). If the loss zone cannot be fixed before running casing, there should be more challenging cementing procedure to undertake an effective casing cement job. Shadravan et al. (2009) explained the effective utilization of underbalanced drilling in Iran. Making the hydrostatic fluid lighter and managing the ECD personifies in underbalanced and managed pressure drilling techniques. Also, during cementing operations, the utilization of sealant spacer fluid could be conducive to cure loss circulation. Farahani et al. (2014) and Budiawan et al. (2014) reviewed 60 case studies where lost circulation was resolved by the application of a biodegradable sealing spacer system. Brandl et al. (2013) improved displacement efficiency by applying a spacer system designed with microemulsion technology in the South China Sea. Kefi et al. (2014) performed a statistical analysis for surfactant selections. Mansure (2002) used polyurethane at Rye Patch for cementing and overcoming loss circulation. Foam cementing has been also a very effective way to cure loss circulation challenges and providing effective zonal isolation in geothermal wells. The battle of lost circulation seems to be everlasting in geothermal wells however with the right solution it could be prevented or minimized. 4. MODELING Temperature is one the most crucial factors strongly affecting the cement placement time and loss of mechanical strength. Correct estimate of temperature and pressure profile along the wellbore in geothermal wells can facilitate the drilling operation by planning the proper slurry design. After drilling, it is necessary to monitor periodically the characteristics of a geothermal well, by measuring the thermodynamic parameters of the flow. However, it is not always possible to run pressure temperature survey (PTS) due to the high cost and limited availability of wells for testing. In order to avoid shutting in a producing well, it is common practice to employ a wellbore flow simulator to estimate the bottomhole operating conditions from wellhead measurements. Some geothermal reservoirs are super-heated and the producers have single phase flow (steam) through the entire wellbore, yet the flow in most of the geothermal wells, are two phase (steam and water). The goal is to find the pressure, temperature, and enthalpy profile of the well by knowing the well head conditions. This will help analyze the range of temperature and heat to which casing, cement, and the formation are constantly exposed. The two phase geothermal wells are discussed, however the single phase flow ones can be found similarly. 4.1 Conservation of Mass Based on the continuity equation, the changes in the mass flow rate of liquid and gas at a section of the pipe should be constant (assuming pipe section is constant). Thus, it can be formulated as (Gudmundsdottir, Jonsson, & Palsson, 2012):

One can expand this equation as,

𝑑 (𝑚̇ + 𝑚̇𝑔 ) = 0 𝑑𝑧 𝑙

(1)

𝑑 (𝜌 𝑢 𝐴 + 𝜌𝑔 𝑢𝑔 𝐴𝑔 ) = 0 𝑑𝑧 𝑙 𝑙 𝑙

(2)

4.2 Conservation of Energy The conservation of energy states that changes in the specific enthalpy (𝑑ℎ/𝑑𝑧) is equal to the heat exchange with rock formation (𝑄̇ ), and the changes in the kinetic and potential energy for each phase as, 𝑢𝑔2 𝑑 𝑢𝑙2 (𝑚̇ 𝑙 ( + 𝑔𝑧 + ℎ𝑙 ) + 𝑚𝑔̇ ( + 𝑔𝑧 + ℎ𝑔 )) + 𝑄̇ = 0 𝑑𝑧 2 2

(3)

By using the mass fraction 𝑥 = 𝑚̇𝑔 /(𝑚̇𝑙 + 𝑚̇𝑔 ) and rewriting the actual phases velocities in terms of the uniform flow velocity as 𝑢𝑙 =

𝑚̇𝑙 1−𝑥 = 𝑢, 𝜌𝑙 𝐴𝑙 1 − 𝛼

𝑢𝑔 =

𝑚̇𝑔 𝑥 𝜌𝑙 = 𝑢 𝜌𝑔 𝐴𝑔 𝛼 𝜌𝑔

(4)

the equation in (3) can be written as, 𝑚̇

𝑑 (1 − 𝑥)3 𝑢2 𝜌𝑙3 𝑥 3 𝑢2 𝑑ℎ ( + ) + 𝑚̇𝑔 + 𝑚̇ + 𝑄̇ = 0 𝑑𝑧 (1 − 𝛼)2 2 𝜌𝑔2 𝛼 2 2 𝑑𝑧

(5)

where 𝛼 is a void fraction that is a critical factor in predicting the pressure and temperature behavior. Here we just mention the homogenous model, however one can look into (Guomundsdottir, 2012) for further discussion. The mixture of water and vapor considered homogenous if they both travel at the same velocity. If it is assumed that these two phases are separated into two streams that flow in different velocities, then one can use slip ratio, 𝑆, to generalize the homogenous model as,

4

Shadravan, Ghasemi and Alfi −1

𝑥 𝑥 1−𝑥 𝛼 = ( )( + 𝑆) 𝜌𝑔 𝜌𝑔 𝜌𝑙

(6)

4.3 Conservation of Momentum The momentum equation consists of pressure changes, friction, acceleration (kinetic), and gravity forces. The density should be the averaged density based on void fraction and the velocity should be the flow velocity. This equation is given as, 𝑑 𝑑𝑝 𝜙 2 𝜌𝑓 2 (𝑚̇𝑙 𝑢𝑙 + 𝑚̇𝑔 𝑢𝑔 ) + 𝐴 + 𝐴 ((1 − 𝛼)𝜌𝑙 + 𝛼𝜌𝑔 ) 𝑔 + 𝑢 =0 𝑑𝑧 𝑑𝑧 2𝐷

(7)

where the 𝑓 is the Fanning friction factor for calculation, 𝜌 is the fluid density, 𝐷 is the wellbore diameter, 𝑢 is the fluid velocity, and 𝑔 is the gravitational acceleration, 𝜙 2 is the frictional correction factor (Gudmundsdottir, Jonsson, & Palsson, 2012). The wellbore simulator is developed by solving the equations (1) - (7) numerically assuming that the pressure, temperature and flow rate is known at the well head. A geothermal wellbore simulator for single and two phase flow in a vertical well with multiple feedzones was developed by (Björnsson, 1987). Later, Aunzo et al. (1991) extended this simulator to H2O-CO2 and H2O-NaCl systems. Chen et al. (2003) developed a simulator for deviated geothermal wells with multiple feed zones based on finite difference. Recently there has been some development on an integrated reservoir-wellbore-pipeline model to simulate the surface facility coupled with subsurface flow (Butler & Enedy, 2010). This may lead to a large scale model that can be computationally expensive to run. However, one can reduce this complexity by applying multiscale simulation (Ghasemi et al., 2015) or model order reduction (Gildin et al., 2013).Various commercial software for simulations related to oil and reservoir production can also be modified to be used in geothermal wells (by considering water and steam properties). This modeling tool provides a good estimate of temperature and pressure profile for wells without pressure temperature survey. It is also capable of modeling heat loss in the casing, cement, and reservoir rock. Figure 4 shows a comparison of temperature and pressure profile for a well in The Geysers with available PTS data. This figure indicates a good match between the model and the actual measurement. The temperature profile is in the 2% bound and the pressure is in the 5% bound of the nominal model. Note that the PTS data for pressure at the lower depth diverges due to the fact that the well was shut in towards end of this test.

Figure 4: Pressure and temperature profile compared with PTS data for a geothermal well in the Geysers, CA

5. CORROSION Geothermal wells continuously produce endogenous corrosive fluids, such as H2S, requiring operators to plan for safety precautions. The extreme high temperature produced from geothermal wells creates a detrimental environment to production casing and wellhead. As an important consideration in every geothermal well, one can mention corrosion and scaling problems. Chemical components present in geothermal fluids can be highly corrosive for metallic and nonmetallic parts of geothermal wells. Materials such as carbon dioxide, hydrogen sulfide, ammonia, oxygen, hydrogen and chloride can play a dominant role in corrosion of metallic parts. So far, there have been several investigations for identification of corrosion effects on different types of material (Conover, Ellis, & Curzon, 1981). Alescio et al. (1999) also presented installing coiled tubing injection strings before putting the geothermal wells on production in Italy. This method due to using corrosion resistant alloys is expensive however it would reduce the need for work over operations. 5

Shadravan, Ghasemi and Alfi 5.1 Corrosion Mechanism Corrosion and erosion in underground wells can be caused by internal or external elements. These elements could be listed as below: 5.1.1 General Corrosion One of the main corrosion agents in almost every geothermal well is carbon dioxide. When CO2 comes with water or steam, it forms carbonic acid, which is a main reason for metal corrosion. There are two principal forms of CO 2 corrosion: mesa attack, which is a localized CO2 corrosion form, and pitting, which is a localized attack with penetration and removal of metal. The most common mechanisms of CO2 corrosion process is listed as below: 𝐻2 𝐶𝑂3 + 𝑒 − → 𝐻 + 𝐻𝐶𝑂3 − 2𝐻 → 𝐻2 Which can turn iron to ferro

𝐹𝑒 → 𝐹𝑒 2+ + 2𝑒 −

So we have the overall reaction as 𝐶𝑂2 + 𝐻2 𝑂 + 𝐹𝑒 → 𝐹𝑒𝐶𝑂3 + 𝐻2 As a result, iron carbonate FeCO3 precipitates on metal surfaces. 5.1.2 Erosion Corrosion Mechanical removal of passive layer of the casing is caused by well fluid flow. This can end up having higher rate of chemical corrosion. The passive layer can protect metal parts from chemical corrosion by the means of the cover formed by precipitated layer on the surface (Hassani, et al., 2012). This kind of corrosion is always seen in high flow rate wells (Sami & Mohammed, 2008). Presence of solid particles or bubbles in liquid flow can increase the rate of erosion corrosion through the wear they make on inner surfaces. 5.1.3 Sour Corrosion (by H2S) Metal parts can be deteriorated when they get in contact with H2S and water. Water is an important element to make H2S a corrosive material (Ray, Randall, & Parker, 1978). As for all the weak acids, the acid made by reaction of H2S and water can release hydrogen ions. The remaining products are iron sulfides (FeSx). This can lead to another form of passive layer deposition. The overall equation can be written as: 𝐻2 𝑆 + 𝐹𝑒 + 𝐻2 𝑂 → 𝐹𝑒𝑆𝑥 + 2𝐻 + 𝐻2 𝑂 5.1.4 Pitting Corrosion This is a highly localized corrosion type that can lead to creation of holes on metal surfaces. The first element causing pitting is chloride ion. Other ions like sulfate or heavy metal ions can also be effective in pitting corrosion. First, oxidation of metallic elements (mostly Fe) occurs: 𝐹𝑒 → 𝐹𝑒 2+ + 2𝑒 − And the anode forms a site for pit. Then, at cathode side, reduction of oxygen takes place as: 𝑂2 + 2𝐻2 𝑂 + 4𝑒 − → 4𝑂𝐻 − As the process continues by oxidation of Fe, ferro ions accumulate at pitted site of the anodic side. Accumulation of positive charge on pitted sites attracts chloride ions present in the fluid, leading to the reaction followed: 𝐹𝑒 2 + 𝐶𝑙 − → 𝐹𝑒𝐶𝑙2 The chain reactions can continue till all the Fe metal is transformed. However, because of low concentrations of oxygen in geothermal wells, chloride ion tends to participate in general corrosion process. 5.2 Corrosion Rate Material used in geothermal wells can show different resistance to corrosion agents. In order to get a sensible time for corrosion effects, we need to quantify corrosion rate for each case, all of which have the basis of distance over time. As a very common unit, one can mention mile per year (mpy) which is the rate of penetration into the metallic material. As an example for the relation of resistance quality and corrosion rate, Fontana (1986) presented some results as shown in Table 2.

6

Shadravan, Ghasemi and Alfi

Relative to Corrosion resistance

Table 2: Corrosion resistance and corrosion rate relativity Corrosion rate

Outstanding Excellent Good Fair Poor Unacceptable

(mpy)