Sand Control and Management Strategies in a Low-Permeability Sandstone Oil Field

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31002, “Lessons Learned From Optimizing Sand Control and Management Strategies in a Low-Permeability Sandstone Oil Field,” by Babalola Daramola, SPE, Propellio, and Chidubem Martins Alinnor, SPE, consultant, prepared for the 2021 Offshore Technology Conference, Houston, 16–19 August. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. The complete paper presents lessons learned from optimizing sand control and management strategies for an offshore Nigerian oil field after multiple sanding events and well failures. The authors discuss selection of the previous sand control solution, failure root causes, and remediation options considered. Introduction Field E is in a water depth of 500 ft. It features unconsolidated sands interbedded with siltstones and mud rocks, and was developed with five horizontal production wells (A1 through A5), two horizontal water injection wells (W1 and W2), and two gas injection wells (G1 and G2) drilled from an offshore platform. The produced oil from Field E is exported by pipeline to a storage terminal and exported by shuttle tanker to market. The produced gas is reinjected into the reservoir. Field E achieved first oil production in December 2013 and had produced 43 million STB of crude oil by December 2016 (a current oil recovery factor of 13%). Field E’s development wells were completed with 13Cr 5.5-in. tubing, permanent bottomhole pressure and temperature gauges, gas-lift valves, and chemical-injection valves for scale and hydrate management. Initial Standalone Screen (SAS) Selection and Installation Although core samples were collected from two appraisal wells in Field E, a sand-strength study was not completed before drilling because of existing field analog data and cost-saving reasons. Sand-production prediction was based on the Niger Delta reservoir rule of thumb, which assumes that reservoir sands at depths shallower than 10,000 ft true vertical depth subsea (TVDSS) are unconsolidated and are expected to fail. The target reservoir was at a depth of 9,450 ft TVDSS and was expected to produce sand. Field E’s rock unconfined compressive strength was not measured, with 2,000–8,000 psi assumed based on field analog data. SASs were selected for sand control because most neighboring oil fields used them as well. The complete paper includes failure root-cause analyses of all four wells; this synopsis will include analyses of Wells A2 and A3.