High Angle Frac Pack Completions in Shallow Sands: A Case Study on Program Learnings and Operational Improvements
Authors: Ibrahim Azhar , Romero Edgar Eduardo , Woon Geok Cheen , Chiu Chee Yang 
Published: March 2015

Telok is a gas field development in the Malay Basin, off the coast of Terengganu in Peninsular Malaysia. This paper discusses the program learnings and operational improvements captured while completing eight new wells in 2012 and 2013.

The primary reservoirs targeted in the field require sand control, specifically frac pack technology, due to the high fines content. Long frac pack intervals (up to 60m) at inclination up to 75 degrees were designed using alternative path screen technology to maximize reservoir exposure as well as to obtain high injection rates and proppant concentrations during frac pack operations. This resulted in relatively high treating pressure.

The frac pack operation on the second well in the campaign presented operational challenges. Several top-up jobs were performed but no screenout indication was observed even though proppant pumped downhole exceeded the initial planned volumes by 20klbs. Reconfirmation stresses showed very low blank fill / insufficient blank coverage. The final top-up job was performed as a circulating pack instead of a frac pack, successfully packing the casing/screen annulus.

Further analysis of the frac pack operation identified the shallow vertical depth of the sand and the associated low overburden stress as a key root cause of the issue. The shallow vertical depth of the sand resulted in the injection pressure exceeding overburden stress, creating a horizontal fracture. It was concluded that the frac pack treatments have to be optimized by controlling net pressure and fracture geometry.

Several lessons were learned and improvements were developed from this well that were applied throughout the remaining campaign and will be discussed further in the paper. In order to overcome the challenge of high treating pressure associated with long sand control intervals with low overburden stress due to the shallow vertical depth, improvements were implemented such as managing the standoff from the top and bottom of the sand interval to the shale and optimizing gel loading in the frac pack fluid to increase fluid leak off.

Introduction

Telok field is a faulted, east-west trending anticline in the Formation A reservoir. The major reservoir in Telok is the Formation A sands, containing dry non-associated gas (NAG). The Formation A reservoir is located at approximately 700–800m TVDss and is laterally extensive across Telok, Tabu, and Guntong fields.

Minor non-associated gas (NAG) reservoirs are the Formation B group and Formation C group sandstones. Formation B and C reservoirs are located between 1,100 to 1,900m TVDss.

Sand control was performed for the Formation A and B-1 reservoirs based on offset well's performance and sand screening evaluation completed based on data from a Telok exploration well.

Sand production was observed during production tests in the exploration wells drilled in the Formation A reservoir. Sieve analysis conducted on core material collected from the exploration wells, together with sand strength modeling work, confirmed that the Formation A sand is friable and would produce sand on initial completion with a high percentage of fines.