Abstract

Baram Delta Field is a mature hydrocarbon-producing field in east Malaysia. The reservoirs are predominantly friable and unconsolidated. Downhole sand-exclusion systems are required to help ensure prolonged well productivity.

Historically, most wells were completed with internal gravel packs (IGP) and high-rate water packs (HRWP) with good success rates. However, there were concerns of inconsistent final completion skins that could result in wells not producing to full potential.

In an effort to improve and optimize sand-control techniques, the frac-pack technique was introduced to achieve not only sand exclusion but also provide additional reservoir stimulation.

This paper describes the transition of an idea from sand control only to optimizing production through reservoir stimulation. A reservoir selection process for applicable frac- pack treatments is also reviewed.

Because this technique was relatively new to this field, fracture design analysis was thoroughly reviewed before the actual application in an effort to ensure maximum benefit from the treatment.

This paper is intended to systematically translate and interpret the field data acquired, with the aim of improving the quality of the job, the fluid design, and pumping diagnostic stage to achieve TSO (tip screenout) fracs.

It is expected that variability in skin after frac-pack treatments can be minimized and the best productivity can be achieved by having an optimized fluid design along with standardized pumping diagnostic and TSO design technique.

The well performance from these frac-pack wells was also evaluated to quantify the benefit of these improved techniques.

Introduction

Baram Field is located in the Baram Delta area, 28 km offshore Miri (Fig. 1). It was first discovered in 1963 and the first oil was produced in August 1971. Water depth varies from 60 to 200 ft.

The producing reservoirs comprise many stacked clastic layers of Miocene age. Baram reservoir sands were deposited in the three major environmental settings, predominantly deltaic-coastal fluviomarine inner-neritic deposits and transitional from deltaic to non-deltaic coastal facies grading down to fluviomarine inner-neritic facies. The non-deltaic holomarine inner-neritic deposits at the base grade up to more coastal facies.

Baram main reservoirs consist of alternating oil, water, and gas sands, unconsolidated, with a formation-sand uniformity coefficient (UC) varying from 3 to more than 20.

The previous sand-control technique was primarily slurry or circulation IGP. Some innovative techniques such as stand alone screen (SAS) and expandable sand screen (ESS) in open and cased holes were applied, so far with limited success. Severe sand production was observed from wells completed with SAS or ESS, especially in open hole. A more detailed study indicated that the openhole intervals do have formation sand UC well in excess of 20 with fines (<100 mesh) above 20% by weight. The critical drawdown pressure (CDP) for an onset of sand production in the intervals of interest in Baram is 150 psi, indicating that there is very little drawdown left to induce flow to the desired rates.

It was therefore decided to implement the more reliable conventional sand-control measure by IGP with provision for stimulation by fracturing to improve well productivity.

Completion Strategy

The Baram H and A development campaigns consist of completions with multiple stacked packs applying a combination of frac-pack and HRWP/F treatments. Because of the requirement to isolate the stacked reservoirs, the number of intervals required to be completed per well averages four zones, while four stacked packs were the maximum completed per well.

Production wellbores vary between 7-in. liners and 9 5/8-in. casing. The casings are cemented and perforated with 12- spf big-hole guns and completions are either dual or single. Gas lifting provides artificial lift in all wells.

Most of the wells are highly deviated, extended-reach with well trajectories averaging 70° through the producing reservoirs.

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