Engineering CCUS Injection Wells for Long-Term Performance

CCUS Injection Well Design

The injection well is the intermediary between the processing facilities on the surface and the storage reservoir beneath. Injection well design is an iterative process that incorporates different, interconnected criteria and design aspects - all of which impact the others. If done appropriately, the final design will culminate in a well that fits the project's needs, is sufficient for long-term use, and is cost-effective without compromising safety or utility. This article explores certain aspects of injection well design and installation.

Completion Design

The completion design needs to be determined before the rest of the well is designed. When the completion design is finalized, the well design cascades to attributes that support the completion, such as the tubing, casing, cement, and wellhead.

Completion design is a combination of factors that fall into two groups: those that are controllable, and those that are not. The controllable group includes factors such as the rate and volume delivered to the wellhead, the constituents in the injection stream, and the temperature of the stream at the wellhead. The uncontrollable group includes the characteristics of the storage reservoirs(s) such as, but not limited to, net thickness, porosity, extent, reservoir pressure, fracture pressure, permeability, and the relative permeability of the CO2 and the rock.

Although the formation homogeneity and characteristics are uncontrollable, there are ways to minimize the impact of adverse conditions and maximize the reservoir's benefits, such as using an open-hole completion (which requires no casing and allows direct but uncontrolled access to the rock). The alternative is a cased-hole completion (which uses casing and perforations for targeted and controlled access to the rock).

Open-hole completions provide optimal access to the reservoir rock, allowing injected fluids to flow wherever the rock allows. However, open-hole completions can be problematic for removing possible formation damage and for well repair(s). In addition, if reactive rock exists within the open-hole section of the well, the hole may collapse, thereby blocking entire sections of the open-hole interval. It is for these reasons that wells designed with open-hole completions can sometimes be difficult to drill and ultimately operate. To reduce formation damage and maintain a high injectivity, it is best to drill the section with a minimally invasive drilling fluid, such as fresh or treated water. However, doing so can create wellbore instability due to the drilling fluid interacting with the rock. However, if the well is designed appropriately, the option will exist to later run and cement a string of casing in the open-hole section, if needed.

Cased-hole completions use a cemented casing string and a targeted perforating scheme to force injection fluids into reservoir sections considered the best for injection. In addition, wells using this approach can be drilled with a more robust drilling fluid to reduce the risk of wellbore instability. Wells using this completion method can also be more easily repaired. However, because cased-hole completions are targeted, they may restrict access to the reservoir, which may increase the operating pressure of the well.

Tubing Design

In conjunction with the completion design, the injection tubing must next be selected and designed. The tubing size should be balanced between maximizing the well's throughput and minimizing the final well size. Tubing that is too large will likely result in an unnecessarily high total well cost. However, smaller tubing generates more friction pressure, which translates into a higher surface pressure, which impacts the surface processing equipment.

Tubing must also be mechanically designed to withstand many operating scenarios, including the event that CO2 in the tubing quickly de-pressurizes and thermodynamically causes the temperature to plummet. This can strain the tensile capacity of the tubing and cause failure if inadequately designed. Similarly, downhole completion components such as packers should have the same or greater mechanical and hydraulic capability as the tubing so that a weak point isn’t inserted into the well design.

Additionally, the well should be designed to inject the specific fluid(s) that are delivered to it, meaning the tubing will need to resist potential corrosion caused by the CO2 and other constituents within the injection stream (such as water, oxygen, or hydrogen sulfide). This typically uses steel with elevated chrome and/or nickel content. Packers and downhole completion equipment should also have the same or greater corrosion resistance as the tubing. However, tubing doesn’t necessarily need to be fabricated from corrosion-resistant steel. Instead, it can be built from carbon steel and lined with corrosion-resistant material to keep the injected fluid from interacting with the steel. In this instance, the liner material will need to be tested for compatibility with the injection fluid and its abrasion resistance against wireline tools.

A part of tubing design often overlooked is whether to land the tubing in either compression or tension. Landing the tubing in compression requires that some of the tubing weight rest on the packer. This relieves the need for more robust tubing and specialized wellhead equipment, but it does create the possibility for significant buckling in the tubing string. The buckling can cause tubing and casing wear, as well as premature failure of the tubing or the packer. Tubing that is landed in tension will instead have less ability to buckle, greatly reducing string wear, fatigue, and the potential for failure. However, landing the string in tension requires a specialized tubing hanger and wellhead, as well as an additional effort to latch into the packer. Most importantly, the tubing must be robust enough to withstand the excess tension.

Casing Design

For most wells, a minimum of two casing strings are typically required: a string to protect the groundwater and another string to stabilize and secure the rest of the well. Generally, wells are designed to minimize the number of casing strings for economic purposes, but ultimately, it’s not the engineer who dictates the number of casing strings required. Instead, it is the geologic environment that will be drilled. Disparate factors such as formation pressures, formation fluids, and formation instability all play a part in the design process. Regulatory agencies may also require additional casing strings.

Each casing string will require an appropriate hole size to accommodate it and the requisite cement to isolate that section of the well. In addition, since the casing is a steel tubular that will be impacted by multiple mechanical, hydraulic, and thermal forces, it must be designed to withstand those forces and provide both structural integrity and safe operations for the expected life of the well.

Unlike tubing, casing must be metallurgically capable of resisting corrosion from high chloride native fluids and those injected, or a combination of the two. Although injected CO2 is generally dehydrated, which minimizes the corrosive effects of the CO2, the combination of CO2 and native fluids in the formation creates carbonic acid. Because of this, the casing may encounter more severe corrosion than the tubing. However, it isn’t necessary to have corrosion-resistant metallurgy in a full casing string; only in those sections with direct contact with the corrosive fluids will it help reduce the overall well cost.

Cement

Cement is the mechanism that isolates the annulus between the surrounding geologic strata and the casing, thereby reducing the ability for fluid to leak. Because of this, the cement has just as much importance as the casing, if not more. Inadequate placement of cement can jeopardize the future operability of the well, making it one of the biggest risks when installing the well. Inadequate cement placement can be born from several causes: 1) a lack of bond between the cement and the casing; 2) a lack of bond between the cement and the rock; 3) improperly designed cement slurries that allow fluids to flow through it; or 4) slurries which will dissolve when brought in contact with corrosive fluids.

To mitigate these risks, the cement should be designed to minimize the interaction it will have with the drilling fluid, have the capability to be pumped in a timely manner and set up quickly, and control the reservoir pressure in the well. For CO2 injection wells, the cement should be designed to have both minimal reaction with the generated corrosive fluid and to minimize any flow of that fluid through the cement. Proper cement design and placement will also slow the corrosion of the casing since it will limit the contact the corrosive fluid will have with the casing.

Wellhead

Although it looks like a simple series of flanges and valves, wellheads are composed of multiple components, each having a distinct purpose: the casing head, which is used to install and mechanically suspend the casing as well as support equipment during the drilling process; the tubing head, which is used to suspend the tubing, monitor the pressures on the casing annuli, and support the completions operations; and the injection tree (or “Christmas tree”) which is the series of valves which control access to the well, shut in the well, and monitor the well.

A properly designed wellhead will provide the mechanical and hydraulic capability to withstand the surface pressure and temperature, suspend the tubing and casing strings, and the ability to be installed efficiently. In addition, the wellhead should be designed for efficient removal that doesn’t compromise the integrity of the well or the safety of personnel during an operation.

The wellhead should meet or exceed the metallurgical requirements of the casing and tubing. However, the whole wellhead doesn’t necessarily need to be corrosion resistant, only those parts that will be exposed to the injection stream, such as the tree, tubing hanger, and potentially the tubing head. Like tubing, there are multiple ways to reduce corrosion in a wellhead: coating the steel, using a clad material on exposed surfaces, or building the wellhead from corrosion-resistant steel.

When done well, the final well design should be more than capable of handling the geologic environment and the injection operations and resisting potential corrosion from the injection stream and native formation fluids. Do you have questions about your CCUS injection well project or design? Trihydro’s CCUS team can help.?