Novel Approach to Sour-Gas Treatment Lowers Cost and Limits Safety Hazards
Authors: Carpenter Chris 
Published: March 2019

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193115, “Novel Approaches to Sour-Gas Treatment in Oil and Gas: Onshore and Offshore Facilities,” by Iain Pollitt and Joao Conde, Infinity Oilfield Services, prepared for the 2018 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed.

This paper investigates novel approaches to sour-gas treatment for use in the Middle East that are outside the common oil and gas market and compares them with traditional techniques. The methods presented in this paper were based on one central tenet: deliver a practical, economical solution to producing from an extremely sour [greater than 40,000-ppm hydrogen sulfide (H2S)] gas field. Modified tail-gas treatment units (TGTUs) were found to be economically viable, can be implemented onsite, and can tie in to existing infrastructure with minimal capital expenditure (CAPEX) or operational expenditure (OPEX).

Introduction

A field in the Mediterranean was producing sour gas at a rate that would render production untenable. One of the wells was producing 24,000-ppm H2S with an expected increase to 46,000 ppm within a few years. While the lower rate allowed production as long as it was coincident with other, sweeter wells in the region, the rising sourness eventually would render operation impossible. To counter this trend, a stage-gate process was established to identify potential solutions and an array of technologies was proposed.

The main criteria that have been considered for the selection of gas-sweetening technologies are cost, operability, and efficiency. The selected options would be analyzed on the basis of these criteria using a screening sheet upon which each criterion had been broken into key elements (the screening method is detailed in Appendix A of the complete paper). The selected option ideally should be low-cost, highly efficient, and environmentally friendly.

Offshore Acid-Gas Removal Options

These technologies included the following:

H2S scavengers

Absorption processes

Regenerative absorption

Nonregenerative absorption

Adsorption H2S-removal processes

Regenerative adsorption

Nonregenerative adsorption

Membrane separation

The membrane-separation units consist of many polymerized hollow fibers arranged asymmetrically and formed into loose bundles of membrane elements. When a pressure differential is applied, the molecules diffuse into the pores of the polymeric material and transport (permeation) occurs across the membrane. Membrane units have relatively modest layout requirements, and CAPEX can be modest to high.

Acid-Gas Disposal-Treatment Options

Claus+TGTU. In the Claus process, H2S is treated with air (oxygen) over a catalyst to form elemental sulfur and water. The tail gas from a Claus unit goes through a tail-gas cleanup or TGTU process.

Liquid-Redox Process. Processes in this group absorb H2S from gas streams and react oxygen with the H2S to form elemental sulfur and water. Iron-chelate processes belong to the liquid-redox sulfur-recovery group and are the most commonly used active redox reagents. A chelating agent is generally an organic molecule able to bind with a metallic cation in such a way that the cation is sequestered from the solution.