Scale management, and the modeling and risk assessments that support it at the design stage of a project, is a critical part of the field development process for deepwater oil and gas developments. In many cases, scaling risk assessments are undertaken very early in the appraisal and concept selection process and with minimal supporting data; however, the implications of such studies can drive field design and affect the commercial viability of a project.
H2S scavenging, or “gas sweetening,” is both a safety-critical and economic concern for ensuring trouble free upstream and downstream operations. This GATEKEEPER will discuss the use of triazine as a liquid H2S scavenger. Focal points include method of scavenging, application limits, treatment efficiency, production systems, downstream risks, as well as environmental impacts.
The difficulty in selecting the materials of construction for the topsides portion of seawater injection systems is associated with uncertainty around the reliability and performance of their associated oxygen removal systems.
Common material selection options for seawater injection systems include carbon steel, stainless steels, copper-based alloys, and composites. Other materials, such as titanium and high nickel alloys, may be used in niche applications, but their increased cost ensures that these are not the first line materials of choice.
In GATE's experience, there are many preconceptions based around the comparative costs of reactive versus proactive souring control strategies. One such area is the comparative operating expenditure (OPEX) associated with the use of either sulfate removal or nitrate injection as part of a proactive souring control program.
Work undertaken to support the development of a recent paper published at the 2011 NACE Corrosion conference by GATE, LLC, and a number of our Clients, included a detailed assessment of the respective operating costs for nitrate injection and sulfate removal unit (SRU) deployment. Although the broader content of the paper considered the comparison of scale squeeze versus SRU use for scale control in deepwater projects, the issues raised by this aspect of the cost analysis are worthy of more detailed comment.
Reservoir souring is defined as the generation of hydrogen sulfide (H2S) by bacteria in the reservoir following water injection. A number of factors can influence rates of reservoir souring at producers, including, but not limited to, the location of injection and production wells; reservoir geology; formation water, aquifer water and injection water composition; pressure and temperature; biological control in the injection and production systems; and drilling practices. Proactive and reactive souring control methods can be adopted to prevent, control or alleviate SRB activity or H2S production (Note summary to left).
Deepwater seawater injection projects, whether subsea or dry-tree developments, generally face the dual challenge of scale control and reservoir souring. These challenges are such that practically all deepwater seawater injection projects are forced to adopt a proactive approach that considers the options of designing for production well scale squeezes or applying sulfate removal for scale control and the use of either nitrate injection or sulfate removal for souring control.
Sulfate removal units (SRU) are able to reduce the sulfate content of injected seawater by filtering the water prior to introduction downhole.
Water injection is often an integral part of the field development plan adopted for subsea developments, where projects may not be economically viable in its absence. However, a significant drawback to the use of topsides water injection facilities for offshore developments is the weight and space required for equipment. As outlined in Figure 1, this can typically include pumps, filter packages, deoxygenation and sulfate removal units. These limitations become particularly problematic for retrofit systems with limited design flexibility and for floating production platforms where weight and space are often tightly limited. A relatively recent development has been to move the water injection equipment away from the topsides and to place it subsea.
Careful attention to scale inhibition during the first wave of water injection can reduce your headaches for the long term. Waterflood is a major secondary recovery option for maximizing field production and ultimate oil recovery. Scaling however, is a problematic issue, hindering secondary recovery by forming blockages that can plug vital waterflood components.
Scale has a large tendency to form immediately around the water injector completions due to the mixing of injected brine and formation brine. This is especially true during initial water injection and startup, before the formation water is fully swept away from the completion.
Scale that forms at the injector causes more concern than reservoir scale formation, because at the injector large volumes of processed seawater are being forced through a relatively small, fixed space. Hence, the presence of deposited scales at the injector is more detrimental to the system than scale dropout in the larger reservoir.