Increased activity in West Africa has improved the availability of many services and materials that were not readily available just a few years ago. Technologies that are commonly used in many parts of the world are now available. One technology used globally in deep water, foamed cement, has become readily available in Angola. Its use in deepwater applications has been shown to simplify well planning and logistics and has resulted in increased success and cost savings on current wells. This paper discusses the introduction and use of foamed cement in deepwater cementing in Angola. Included is a discussion of logistics associated with foamed cementing and mobilization of crews, equipment and a comparison of this technology against alternate lightweight cement slurries. Discussed are the logistics for specialty-blended cements, including the need to import specialty cement materials or blends, excess inventories required to cover large contingencies and uncertainties, and associated delivery times. An analysis of the introduction of foamed cement to Angola is presented along with the associated risks of the use of both the foamed cement and alternate specialty slurries. On-location operational considerations for foamed cement are discussed and comparisons are made with the requirements for mixing of specialty lightweight slurries. Introduction Deep water offshore Angola shares many commonalities with deepwater drilling activities worldwide. There is a common need for cement systems that will set at the very low temperatures found in deep water. These systems must be lightweight to combat the low formation strengths in these wells. Uncertainties in cement volumes are a major concern because of extreme hole wash outs, and potential lost circulation. Conventional slurries, extended with either bentonite or silicate extenders, can provide the lightweight density required only to a limited extent. At densities below 11 lb/gal, conventionally extended systems may not have adequate strength development to provide the support required for the upper casing strings. Strength development in these slurries is very slow at cold temperatures. However, depending on the time required to run risers or perform other rig operations before continuing drilling, slow strength development may not be a concern. Unlike some areas, shallow water flows are not prevalent offshore Angola. This factor allows the use of slurries that may not be appropriate for areas with shallow water flow. As a consequence, conventionally extended slurries can be applied where waiting on cement (WOC) time is not an issue and where slurry density can exceed 11.5 lb/gal. Extending cement slurries with ultra-lightweight additives has been practiced for many years.1 These systems use hollow beads or microspheres to lower the density of the cement by introducing encapsulated air. Densities as low as 8 lb/gal are possible with these materials. Because the ultra-lightweight additives are hollow spheres, they are susceptible to crushing at pressure. To combat higher pressures, higher-strength materials are used. As the strength of the material increases, the specific gravity also increases, thus requiring more material to reach the same density. Deepwater West Africa wells can typically have hydrostatic pressures exceeding 5,000 psi. Designer slurries have been developed that incorporate ultra-lightweight additives with selected particle-sized materials to enhance slurry properties and set cement performance. Recent papers have highlighted the successful use of these slurries in West African and other operations.2,3 Foamed cement technology has been developed over several decades.4–7 Slurries have been optimized for stability, and automation of equipment has made the technology easier to apply.8–10 Foam offers a number of technical advantages, two of which are (1) the ability to readily change slurry density at the rig site without adversely affecting slurry properties, and (2) none of the pressure limitations found with the ultra-lightweight extenders. In areas where nitrogen is readily available and logistics allow easy mobilization of the nitrogen to the rig, the use of foamed cement technology offers definite alternatives to conventional or designer lightweight slurries.
The challenges associated with the construction of an injection well for carbon sequestration are cross disciplinary, but highly manageable. Site selection, reservoir identification and formation evaluation involve geological and reservoir specialists that perform detailed evaluations of the subterranean environment.[1–4] Materials selection identifies components that are designed to withstand the unique chemical and physical environments of these wells. Sealant selection is key to providing long term integrity of any well, with Portland cement being the material of choice for most oil field applications. Work on Carbon Sequestration in subterranean formations has renewed interest in investigating the long term effects of CO2 on Portland cements. Portland cement will react with the injected CO2, and while recent research indicates these conventional cements are not a concern, additional work is ongoing to improve the long term effectiveness of the wellbore sealant. Efforts have focused on enhancing the properties of Portland cement by reducing the permeability of the set cement, lowering the concentration of materials in the cement that react with CO2, or replacing the conventional Portland with specialty cements. Complementing technologies that have been used to further promote long term seals include the use of in-situ swell packers, and self healing cements. Additional work has been done in evaluation of the long term stress environment of the well. This work goes beyond the simple drilling and completion of the well to include input from long range reservoir and wellbore stress modeling through the full life cycle of the well. These stresses are evaluated to confirm the selected sealants can withstand the changing stress environment. This paper discusses various identified solutions to the challenges of selecting a proper wellbore sealant for a CO2 injection well. Additionally, the paper reviews the available sealant technologies, their application, and includes a discussion of stress modeling for these wells. Background Successful carbon capture and sequestration (CSS) depends on a identifying a place to permanently store the captured CO2. Geological formations are currently considered the most promising sequestration sites, with three types being considered the most promising: depleted oil and gas reservoirs, unmineable coal seams and deep saline formations. To sequester CO2 into any of these formations requires careful site selection and the proper installation of injection wells. Many of the depleted oil and gas reservoir sites have existing wells, which creates an additional challenge of properly sealing those potential leak paths.
The use of foamed cement systems for deepwater applications has been increasing and is often the system of choice for shallow hazard mitigation as in the Gulf of Mexico. However, there is little information regarding foamed cement behavior under wellbore conditions. Research is being conducted to develop a predictive relationship between the mesostructure and physical properties of foamed cements used in offshore applications. Samples of foamed cement have been generated using both atmospheric laboratory and high-pressure field preparation methods. Field-generated foamed cement samples were collected in constant pressure (CP) sample cylinders using the same full-scale field equipment used to generate foamed cements in a well. These samples were scanned while inside the CP cylinders using X-ray Computed Tomography with a scan resolution of approximately 35 m.Results of the laboratory testing indicate a correlation between foam quality, bubble size distribution and physical properties such as strength and permeability. Initial results also highlight key differences in laboratory and field-generated foamed cements. The variations in cement structure within the fieldgenerated foamed cement samples appear to indicate a strong relationship between the flow of the cement into the sample vessel and the final porosity and properties of the in-place hardened cement. This research will provide a better understanding of the effects that foam cement production, transport downhole, and delivery to the wellbore annulus has on the overall sealing process.
High rate acid gas injection wells pose a significant challenge for the design of cementing systems. CO2 conversion of Portland cement to calcium carbonate is a significant problem. This paper describes the design and use of two cement systems for high rate acid gas injection wells. The paper compares risks and benefits of a high alumina cement slurry to those of a specialty Portland based system. Case history reviews of the application of both systems on liner cement jobs are detailed. The systems were used on wells designed for a 65% H2S, 35% CO2 injection stream at a rate of 65 million scf/day. High alumina cement is used in many applications to address the problem of CO2 conversion of Portland cement. The cement is resistant to CO2, but high temperature fluid loss control was not available, preventing its application on long liners. Lack of an effective high temperature fluid loss additive required the development of an alternate Portland based system. Later development of an effective high temperature fluid loss additive ultimately allowed use of the high alumina cement system. A CO2 resistant Portland system was developed by limiting the cement concentration and reducing total system permeability by use of specialty sized particles. This paper discusses the development and testing of a Portland based cement system and the associated risks with the use of this specialty system. Quality control steps to address the complex blending process and steps taken to improve system reliability are presented. Background Two acid gas injection wells (AGI 3–14 and 2–18) were drilled in the western United States as part of an overall gas plant de-bottlenecking. Plant throughput capacity was being increased by converting the plant to acid gas disposal by injection. The anticipated waste gas stream was 65% H2S and 35% CO2, with the design volume for the wells being based on the capacity of the plant plus adequate backup.
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