Design of Low-Sulfate Seawater Injection Based Upon Kinetic Limits

Abstract

Design of Low Sulphate Seawater Injection Based Upon Kinetic Limits John E. McElhiney; John E. McElhiney Pratt Technology Management Search for other works by this author on: This Site Google Scholar Mason B. Tomson; Mason B. Tomson Rice University Search for other works by this author on: This Site Google Scholar Amy T. Kan Amy T. Kan Rice University Search for other works by this author on: This Site Google Scholar Paper presented at the SPE International Oilfield Scale Symposium, Aberdeen, UK, May 2006. Paper Number: SPE-100480-MS https://doi.org/10.2118/100480-MS Published: May 31 2006 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation McElhiney, John E., Tomson, Mason B., and Amy T. Kan. "Design of Low Sulphate Seawater Injection Based Upon Kinetic Limits." Paper presented at the SPE International Oilfield Scale Symposium, Aberdeen, UK, May 2006. doi: https://doi.org/10.2118/100480-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE International Oilfield Scale Conference and Exhibition Search Advanced Search AbstractReliance on low sulphate seawater as sole protection against sulphate scale may be discomforting to some operators when such expensive subsea wells are at stake. Normal methods such as bullheading squeeze chemicals are nearly impossible to implement due to the long and sometimes multiple flow lines connecting injection wells. Subsea intervention to place squeeze inhibitors is prohibitively expensive due to the requirement of utilizing a service boat over the well for many days.[1] Calculations of scaling index from formation and injected seawater mixtures are routinely based upon the thermodynamics of the mixed brines. Although some mixing does occur in the interwell distance, the most vigorous mixing occurs in the vicinity of the production wellbore where water from multiple layers and streamlines impinge. These near wellbore mixtures have short residence times before being produced therefore reaction kinetics must be considered, and it is not clear how low the sulphate concentration in injected water needs to be to delay scaling downhole. This work offers a fresh look at this scaling problem by examining the kinetics of the mixed brines. Using data from existing field projects that currently inject desulphated seawater, the induction times required for non-scaling fluid transit up production wellbores are chosen, and the sulphate concentrations necessary to provide these induction times are computed from a software program.[2] The software algorithms are based on a broad, robust database of barite kinetics that span large variations in sulphate and barium concentrations, temperatures and salinities.[3] This protocol is compared to scaling index results computed from a thermodynamic approach at both bottomhole and wellhead conditions. A tandem role in which inhibitors can be utilized in conjunction with low sulphate seawater is described.IntroductionWith the development of deep offshore production beginning around the end of the last century the complexion of sulphate scaling problems took on new dimensions. These projects, in waters of depths of several thousand feet, are often developed around floating production and storage offloading (FPSO) vessels. Wells are sometimes tens of kilometers from the vessel itself and are connected from subsea wellheads to the FPSOs by long flowlines. In many cases several production wells are connected by manifolds and produced fluids flow to the FPSOs in a single flowline. These so-called 'daisy chains' are difficult to utilize when treating a single well from the FPSO. In addition, the producing wells themselves are often completed as laterals of significant length with no downhole zone isolation capabilities. There are many projects like this now in the world but some examples are: Girassol, Plutonio, Roncador, Kizomba B, and most of the P-numbered Brazilian projects.[4,5,6,7]In such cases, bullheading inhibitor fluids downhole from FPSOs has become very difficult and expensive.[1] Intervention from a workboat floating over the subsea wellhead can be done, but again is very expensive. As a result, the industry has begun to rely solely upon sulphate removal from the injected seawater as a means of prevention of sulphate scale formation downhole in the producing wells.When it was initially conceived sulphate removal technology (SRT) was not intended to provide total protection against scale formation. In the early 1980s, South Brae in the Brae field complex in the North Sea was under development by Marathon Oil Company and confronted with severe barite scaling problems. The barium concentrations were as high as 2000 mg/l in some reservoir layers and the temperature was 250+ deg F. A two-pronged solution: 1) reduce the sulphate concentration in the injected seawater, and 2) develop a new inhibitor capable of withstanding higher temperature, minimizing reservoir damage and providing effectiveness at lower sulphate concentrations provided by membrane treatment was used. Modification of existing nanofiltration membranes to be sulphate specific in their rejection characteristics provided the capability to lower sulphate concentrations to the 100 mg/l concentration level.8,9 Development of a new polyvinylsulfonate inhibitor provided endurance at high temperatures and was effective at high barium concentrations once sulphate concentrations were lowered into a manageable range.10 At S. Brae an additional problem was encountered early-on before SRT was developed; raw seawater had to be injected to keep the reservoir above the bubble-point in some regions/layers. The tandem approach of SRT and inhibitor worked well when desulphated water was placed ahead of the advancing untreated seawater but due to interpretation of the complex geology this was not possible in all cases. Keywords: paraffin remediation, wax inhibition, asphaltene remediation, wax remediation, oilfield chemistry, scale inhibition, Hydrate Remediation, hydrate inhibition, scale remediation, concentration Subjects: Production Chemistry, Metallurgy and Biology, Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene This content is only available via PDF. 2006. Society of Petroleum Engineers You can access this article if you purchase or spend a download.