Reassessment of Multiphase Pumps for Marginal-Field Development

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165587, ’Reassessment of Multiphase Pumps in Field-Case Studies for Marginal Deepwater Field Developments,’ by N. Abili, F. Kara, and I.J. Ohanyere, Cranfield University. This paper was peer reviewed and published in the February 2014 SPE Oil & Gas Facilities magazine, p. 56. This paper focuses on the applicability of subsea-processing technology (SPT) using multiphase pumps (MPPs) to develop marginal fields commercially. A technology selection consisted of a comparison of performances of several SPTs for effective development of marginal fields and was evaluated further with an analytical hierarchical process, resulting in the most effective innovative SPT for marginal-field development. The findings of this process were validated further in their applications to real fields, reflected in specific field-case simulation studies. Introduction Most of the world’s exploration-and-production companies have a significant number of unconventional and remote fields in their portfolios. Recent industrial effort has been focused on the accelerated development of SPT. One of the innovative solutions is the handling and treatment of produced oil and gas at or below the seabed for transport to topside facilities, to mitigate flow-assurance issues. Some of the notable benefits of subsea processing include mitigation of hydrate formation and management of pressure-related issues resulting from the production of heavy oil, increase in wellhead pressure, and increased hydrocarbon production from fields with low pressure profiles. In ultradeepwater and deepwater fields, subsea processing is the most effective solution because such fields are beyond human intervention (divers), and it is used to boost hydrocarbon production from green fields or brownfields, reducing production cost and the need for topside processing. This paper explores subsea processing in the development of offshore fields. From the concept selection, an optimal or near-optimal solution of SPT was then applied to an offshore-field development. The application of the optimal solution is simulated with a transient-multiphase-flow dynamic-model program, and the production profiles obtained from the simulation are compared with the reservoir’s production profile. The present paper considers results presented on subsea MPPs as a possible solution to develop marginal offshore fields commercially. Results and Analysis of Field-Case Study The simulation covers an 8-year production period simulated over two isolated cases (see the complete paper for discussions of four such cases) with varying water cuts and productivity index (PI). This simulation compared the most-innovative and -effective SPT found through analysis, which is multiphase pumping. The base case is modeled in a transient-multiphase-flow program without any form of subsea processing or gas or water injection. Field A is a typical example, and the current production profile uses an electrical submersible pump (ESP) to boost production; however, this is not modeled here because of the difficulty in handling free gas at suction conditions, because this reduces the efficiency of the pump and creates difficulty in modeling an advanced gas handler or gas separator for an ESP in the transient-multiphase-flow program. Hence, for each of the cases in the 8-year period, we ran concurrent simulations for different field-development profiles. The field-development profiles were simulated for two production cases: Case 1 produces fields without subsea processing (base case without SPT). Case 2 produces fields with subsea processing using multiphase pumping. Field A. The field is located in the North Sea, at a water depth of more than 180 m and a seabed temperature of 4°C. A 26 000-m length of pipeline at an uneven seabed is expected to create slugs in the flowline. The well that was considered was a deviated well with a vertical depth of 1848 m from the seabed and a horizontal distance of 800 m from the wellhead. This is a high-pressure field, with reservoir pressure in excess of 200 bar and temperature in excess of 70°C. Production is through water injection, tied back to a floating production, storage, and offloading vessel. Field B is discussed in detail in the complete paper. Two field-case studies from Field A will be outlined here; please see the complete paper for the results of two field-case studies from Field B.