Simposium Nasional dan Kongres X Jakarta, 12 14 November 2008 Makalah Profesional IATMI 08 018 Experimental Treatments for Fluid-Blocked Gas Wells By Melvin Devadass, Technical Manager, 3M Oil & Gas Markets, APAC Pope, Sharma, Bang, Ahmadi, Linnemeyer from University of Texas and Baran from 3M Abstract 3M Company and the University of Texas at Austin (UT) have been conducting studies to treat the problem of condensate banking around the well bore that reduces gas flow rates when the field pressures drop below the dew point of the condensate. In these studies Berea and reservoir sandstone cores have been treated with a new class of fluorinated materials based on perfluorobutane sulfonate (PFBS). In laboratory experiments at simulated field pressures, temperatures and flow rates gas and oil relative permeabilities were increased by 2-3X in gas condensate blocked wells. Similar studies in the laboratory has shown a 3-5X increase in gas and oil relative permeabilities in water blocked wells. Treatments have also been designed for in situ treatment of the proppants in fractured wells. The treatment appears durable and does not damage the sandstone cores that were tested. Introduction Over time, nearly all gas wells reach a point where well deliverability decreases significantly due to condensate banking or water blockage. Capillary forces trap these liquids in the near the well bore region, which results in a reduction in the relative permeability of both gas and condensate. Eventually this blockage may render the well uneconomical to operate. applied to the proppant in a fractured well. The treatment strives to alter the wettability of the sandstone from a strongly liquid wet state to intermediate gas wet 1 Wettability plays an important role in fluid accumulation around the wellbore. The effect of wettability on liquid accumulation in porous media is expressed by the Young-Laplace equation. P c = (2σcosθ) / r (1) Where, P c is the capillary pressure, σ is the interfacial tension at the gas-liquid interface, θ is the pseudo-contact angle and r is the mean radius of curvature of the gas-liquid interface. Thus, according to the Young- Laplace equation, decreasing the cosine of the pseudocontact angle for a given liquid will correspondingly decrease the capillary pressure and thus may increase well deliverability by decreasing condensate accumulation or water around a wellbore. 2 The fluorinated materials have been designed as possibly a more economical, longer-lasting and more effective method of stimulating blocked wells than hydraulic fracturing, gas cycling, drilling new wells or other conventional methods. 3M and UT have created formulations based on fluorinated materials that can treat fluid blocked wells. These treatments can also be
Fluorochemical Materials Fluorinated materials are both oleophobic and hydrophobic. Fluorochemical compounds are well known and commercially used, among other things,, to lower the surface-energy of various substrates in order to provide desirable macroscopic properties such as stain and soil repellency and release. Fluorinated materials are also robust under very harsh conditions involving temperature, ph, high brine, etc. These characteristics make fluorinate materials ideal for use in the petroleum industry. In the oil and gas industry, it has been common practice to inject well stimulation fluids into selected oil and/or gas-bearing geological formations to overcome problems resulting in reduced production. Typically, well stimulation fluids operate by hydraulic fracturing and/or acidic reaction with the formations. The well stimulation fluids may prevent a decrease in the permeability of the formation to oil and/or gas and also prevent a decrease in the rate of delivery of oil and/or gas to the wellhead. While fluorochemical compounds are known as components in well stimulation fluids, not all fluorochemical-based materials are suitable as well stimulants. Some do not provide imrovements in production, while others provide some stimulation, but are not durable and thus, in practice, do not provide adequate sustained performance. Fluid Blocked Gas Wells Two primary conditions lead to fluid block in gas wells. These are the formation of gas condensate and water invasion in the near wellbore region or a combination of both. The following briefly describes the formation of these fluids in a typical gas well. Gas Condensate Reservoir Condensate Blocked Wells Figure 1 graphically represents a gas producing formation. Gas flows from the right to be produced in the wellbore on the left. In the near wellbore region, the pressure drops below the dew-point pressure of the reservoir. This decrease in pressure results in the production of condensate. The condensate accumulates in the pores of the formation and inhibits gas production. Water Blocked Wells In water blocked wells, liquids invade the near wellbore region during drilling, completion and workover operations. Water could also be a result of cross-flow from a higher pressure water bearing zone. This penetration of liquids (mostly aqueous) can cause a loss in gas well deliverability over an extended period of time. The loss in production can be significant in the case of depleted, low permeability formations. Typically the damage done by water is more detrimental to the well productivity than that caused by condensate. This can be attributed to the high surface tension of water. Other typical ways to treat these problems would be to create a fracture in the formation. This will provide temporary relief from the fluid blockages, but the problem will eventually recur and will be more difficult to treat because the condensate will form radially along the length of the fracture. Laboratory Experimentation and Results In laboratory experiments at simulated field pressures, temperatures and flow rates, application of the experimental treatments increased flow rates through cores as much as 1.75 to 3.0 times their original flow rates. The experimental treatment appears durable, and did not damage the sandstone cores that were tested. 2,3 Laboratory testing was conducted in a temperature controlled oven as described below in Figure 2. The apparatus is made up of three cylinders on the right that serve as accumulators to hold the synthetically prepared gas condensate mixture. The condensate mixture is formulated to mimic various characteristics of actual condensate fluids, such as viscosity, drop out pressure and
content, interfacial tension, and so on. The apparatus is also equipped to measure the viscosity of the system for additional calculations. BPR-1 (back pressure regulator) maintains the pressure above the dew point pressure. BPR- 2 maintains the rest of the experimental setup below the dew point. BPR-1 is opened and the condensate is flashed into the core to produce the condensate. The core holder on the left holds the core and pressure taps the length of the core are used to determine the pressure drop at various points in the core. Once steady state has been achieved, the treatment solution is injected and the core is shut-in. The gas condensate mixture is then re-introduced and allowed to come to steady state. The improvement due to the treatment is then determined from the pressure drop before and after the treatment. Core flood experiments in condensate banking studies were carried out under a wide range of parameters: Temperatures ranging from 145 F to 322 F Single phase pressures from 3,000 to 6,000 psi Two phase pressure from 500 to 3000 psi Initial water saturations from 0 to 80% Sandstone cores with relative permeabilities ranging from 0.1 to 512 md Capillary numbers from 10-6 to 10-3. The relative permeability measurements were determined before and after the treatments and are tabulated as an Improvement Factor (PI). The improvement factor is calculated by dividing the relative permeability after treatment by the relative permeability before treatment. Representative Improvement Factors for condensate blocked wells are shown in Table 1. Figure 4 below shows the gas relative permeability values both pre and post treatment and in for cores having an S wi of 60 % and after flowing 1 pore volume of brine through the core after treatment. The results indicate that the chemical treatment using the fluorinated material could significantly reduce the damage caused by water blocking. In the laboratory, the treatment was sustained even after flowing several pore volumes of brine and solvents. Laboratory experiments on fractured cores have targeted in situ treatment of the proppants in the fracture zone. Similar results have been obtained in these experiments. The data has also shown that the treatment may eliminate or reduce non-darcy effects thereby increasing the perceived improvement factor even further. The experimental treatments discussed above are based on a technology developed in conjunction with the University of Texas at Austin (UT). 4 The treatment mixtures consist of a fluorinated material dissolved in glycol and alcohol or in glycol ether and alcohol. The chemistry of both treatments is non-reactive to avoid formation damage. Case Reference The first trial in the United States of the experimental gas well stimulation product, L- 19945C, was performed on a well with the following general characteristics: Sandstone Fractured Volatile Oil Well Bottom Hole Temperature 200 F Bottom Hole Pressure ~1250 psig Salinity 22,000 PPM Total Dissolved Salt (avg.) Initial Water Saturation 30% The well began gas production in December 2006. The gas production steadily declined to 18% prior to the treatment in March 2008. Extension of the well s gas decline curve in green indicates (figure 5) the well would have continued to decline and would have likely become uneconomical in 2008. The well was initially cleared of built-up fluids. The treatment was then introduced into the
well fracture and shut-in for approximately 18 hours. The average production improvement for gas in the 60 days following treatment was greater than 1.4X. The orange line indicates the best fit of the post treatment gas data. Figure 5 shows the gas production performance improvement (PI). The PI is calculated as the ratio of the post-treatment gas production to the expected gas production in the absence of treatment. The results of this field trial are a typical example of performance improvement expectation from the experimental gas well stimulation treatment. Proposed Application Process The surfactant treatment could be applied with equipment commonly used for other well maintenance and remediation procedures. A predetermined volume of treatment solution would be pumped downhole. The treatment solution would be bullheaded into the nearwellbore region at pressures above the bottom hole pressure, but below the fracture pressure of the formation. Treatment zones may be isolated if required. The treatment solution is typically chased with gas (dry methane or nitrogen) at a defined pressure. The treatment/chase gas pressure would typically be at about 5,000-6,000 psi. The treatment is then shut in for a defined period of time, typically from 10 to 15 hours. In most cases, an improvement in flow rate will be noted almost immediately. It has been found that quantifiable improvements may take up to a month to be realized. When treating a fracture, a coiled tubing unit (CTU) can be used to apply the treatment. In this kind of application, a slug of gas would be injected after the shut-in period to over-displace the treatment. Application Information Experimental Materials References. 1 Li, K. and Firoozabadi, A., Experimental study of wettability alteration to preferential gas-wetting in porous media and its effects, SPE Reservoir Evaluation Engineering, 3(2), 2000. 2 Kumar, V., Pope, G., Sharma, M.: "Improving the Gas and Condensate Relative Permeability Using Chemical Treatments," paper SPE 100529, presented at SPE Gas Technology Symposium, Calgary, May, 2006 3 Kumar, V: "Chemical Stimulation of Gas Condensate Reservoirs: An Experimental and Simulation Study", PhD Dissertation, The University of Texas at Austin, May 2006. 4 Development of a Successful Chemical Treatment for Gas Wells with Condensate or Water Blocking Damage PhD dissertation, University of Texas at Austin, December, 2007.
Near Wellbore Region Single-Phase Gas Region Gas-Oil Flowing Oil at Residual Only Gas Flowing S wi+c P dew Gas S wi P wf Gas Condensate Reservoir Figure 1. Gas Condensate Reservoir BPR-1 Core Holder Capillary Viscomete BPR-2 Pressure Transducers RUSKA Pump Figure 2: Core Flood Schematic Effluent
Figure 3: Actual Laboratory Set-Up for Core Flood Experiments Treatment Temperature ( F) Swi Brine PI Improvement Factor L19945 275 24% 7.5% 2.16 L19973 175 19% 7.5% 2.07 L19945 279 15% 22.8% 1.80 L19973* 175 19% 7.5% 2.08 Table 1: Treatment results on reservoir core containing naturally occurring connate water.
Figure 4: Increase in Gas Relative Permeability after treatment for Water blocking. Pre-treatment k rg (Swi=60%) Post-treatment k rg (Swi=0%) k rg (After establishing Swi=60% in core) k rg (After injecting 1 PV of water in core) Capillary Number k rg k ro 9.73E-06 0.021 0.005 1.33E-05 0.031 0.007 1.80E-05 0.045 0.011 7.13E-06 0.113 0.028 1.85E-05 0.163 0.040 9.99E-06 0.081 0.020 2.05E-05 0.147 0.036 3.71E-05 0.187 0.046 7.99E-06 0.101 0.024 1.94E-05 0.156 0.038 Table 2: Water/Condensate Flood Results Summary
Figure 5: Gas Production-Pre and Post Treatment.