This paper presents insights gained from analyzing and modeling acid gas (H2S and CO2) injection well performance over the last 13 years. As the world increasingly develops oil and gas reservoirs that contain significant concentrations of H2S and CO2, the number and size of acid gas injection facilities and their associated acid gas injection wells will increase. A methodology to estimate wellhead operating pressures satisfies a key requirement for design of the injection wells and sizing of the acid gas injection compressors. It may also help inform engineering and operations personnel, and regulatory agencies, of the complex behaviour of acid gas injection wells.The initial impetus for this work was an operator who increased the acid gas injection rate on a well yet saw virtually no change in wellhead operating pressure, which is inconsistent with water injection well operations. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behaviour with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore.Pressure gradients in aquifers or reservoirs suitable for acid gas sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 10 3 m 3 /d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, fluid composition and wellhead temperature on wellhead pressure. Depending on conditions, injected acid gas may undergo phase transitions from a gaseous or two-phase mixture at the wellhead to liquid at the sandface and back to gaseous or supercritical out in the reservoir. The complex interactions between temperature, phase behavior, fluid density and pressure can lead to unusual operating characteristics including an increased injection rate or sandface pressure with little or no change in wellhead pressure.
This paper uses the experience gained over the past 13 years in analyzing and modeling wells that inject mixtures of hydrogen sulphide and carbon dioxide from sour gas plants to model the operating performance of injection wells for long term CO 2 sequestration from electrical power plants. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behavior with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore.As the world embarks on large scale capture and injection of CO 2 emissions from electrical power plants, understanding the operating characteristics of the injection well(s) will be critical to the design, construction and operation of these systems. Unlike water injection wells, increasing the injection rate for a CO 2 well does not necessarily increase its wellhead operating pressure. A methodology to estimate wellhead operating pressures is a key requirement for the proper design of the injection wells and the CO 2 surface facilities. It may also help engineering and operations personnel, as well as regulatory agencies to understand the complex behavior of CO 2 injection wells.Pressure gradients in aquifers or reservoirs suitable for CO 2 sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 10 3 m 3 /d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, CO 2 stream composition and wellhead temperature on wellhead pressure. Depending on conditions, the CO 2 stream may undergo phase transitions from a gas or liquid at the wellhead to dense phase fluid in the wellbore and back to gaseous or supercritical out in the reservoir. The complex interactions between phase behavior, fluid density and pressure can lead to unexpected operating characteristics, including an increase in injection rate or sandface pressure with little or no change in wellhead injection pressure. IntroductionUnderground injection and storage is a highly specialized method of dealing with the hydrogen sulphide (H2S) and carbon dioxide (CO 2 ) "acid gas" by-products from a sour gas processing plant. Underground injection was initially developed for small "nuisance" volumes of acid gas, typically less than 14 10 3 m 3 /d (500 Mscfd), that were too large to vent directly to atmosphere but were too small to justify processing through a Claus sulphur plant; the conventional method of treating H2S. However, since the 1990's a worldwide increase in sulphur supply and ongoing market volatility has increasingly led to investigation of acid gas injection and storage as an alternative to all sizes of Claus plants and long-term surface stockpiling of elemental sulphur. Wall and Kenefake (2005) describe a 1,845 10 3 ...
Summary An integrated geological and engineering framework of the Kirby Wabiskaw B reservoir has permitted a retrospective analysis of two steam flood pilots that failed to achieve commercial success. The analysis identified four factors that negatively impacted the pilots and which would need to be addressed prior to future steam floods. The factors are: Laterally extensive calcite cemented horizons, interbedded mudstones, pore plugging kaolinite and clay diagenesis upon contact with steam. Introduction Beginning in the late 1990's, and continuing to 2005, significant debate has raged in Alberta on the advisability of permitting the depletion of gas overlying immobile bitumen. Unlike conventional oil recovery, depletion of a gas cap does not directly affect reservoir drive for bitumen. In a steam flood, the overlying gas creates a pressure blanket that prevents steam escaping from the bitumen zone. Owners of the bitumen rights assert that the bitumen represents the greater asset to the Province of Alberta and that gas production should not be permitted until such time as the bitumen is recovered. In general, it has been accepted that a minimum of 10 metres of bitumen pay is required for thermal recovery. The authors were commissioned to conduct a widespread and detailed examination of the bitumen deposits in the Kirby area to map regions of exploitable bitumen and, by extension, where the gas may be produced in those regions of thin, non-exploitable bitumen. Over 1000 well were evaluated in the study with bitumen, gas, and water thicknesses mapped and hydrocarbon saturations determined. Cores from over 40 wells where described in detail with 16 thin sections collected from 4 of these wells. Scanning electron microscope (SEM) and X-ray diffraction (XRD) were performed on 7 samples to determine clay types and distribution within the reservoir. Isotopic analysis was undertaken on 5 samples of calcite cements to determine stable isotope (carbon and oxygen) composition. Our work compliments the more extensive petrographic, SEM and XRD work of Dekker et al1, Beckie and McIntosh2, and Shier3. Our stable isotope investigation of calcite cements augments the work of Shier3. Analysis of permeability and bitumen saturation of cored wells within Townships 73–74 Range 8W4M and from two steam pilots in section 29–73–7W4M and section 1–73–6W4M was also undertaken. These analyses were compared with bitumen saturations and permeabilities from core in the Hilda Lake Clearwater SAGD pilot (Township 64 Range 3W4M). Engineering appraisal was undertaken on the two pilot sites (IHOP and PHOP Fig. 1) in the Wabiskaw B Formation and at the Cold Lake and Hilda Lake sites in the Clearwater Formation (Townships 64–65 Range 3 W4M). The result was a refined geological framework which permitted a retrospective understanding of the two Wabiskaw B steam flood pilots that, while each having in excess of 20 metres of bitumen pay, failed to achieve commercially viable production rates. This paper examines the geological and engineering evidence on macro, meso, micro and molecular levels, each of which contributes to the explanation of the performance of the pilots. The Wabiskaw B reservoir, within the Kirby area of Alberta (Townships 71–75 Ranges 3–10), occurs between the Cold Lake thermal recovery projects to the south and the Athabasca bitumen mining projects to the north (Fig. 1)The Wabiskaw B is a significant bitumen resource with total pay of over 30 metres in the thickest part of the reservoir. Viscosity of the bitumen varies from 30,000 to 82,300 mPa necessitating thermal recovery techniques. Upon first examination, the log characteristics appear comparable to the successfully steam flooded Cold Lake Clearwater reservoir in Townships 64 - 65, Range 3W4M (Fig. 2).
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