Abstract

This paper discusses analyses undertaken to address well failures at the Matagorda Island 623 field in the Gulf of Mexico shelf. All of the 17 development wells producing the main reservoir have experienced some form of well failure or casing damage during the past 16 years of production. A comprehensive review has been undertaken and a suite of studies conducted to determine the root cause of the failures, and to predict well life of existing wells and new in-fill wells. Based on the study, practical advice is presented that was applied in recent replacement wells. The particular merit of this paper is that it covers field problem case histories, advanced analytical approaches, and practical measures for implementing prediction results.

Background

Matagorda Island 623 Field is located offshore southeast Texas within the continental margin of the Gulf Coast basin. It is one of several large gas fields along the prolific Lower Miocene normal growth fault trend in the Brazoria-Matagorda Island area where over 3 TCF gas reserves have been discovered. The field contains a series of stacked, highly overpressured gas bearing sandstone reservoirs that reside between the depths of 9000 feet and 13500 feet subsea. The structure of the field is typical of the Texas Offshore Corsair Trend, in which a dominant listric growth fault (characterized by greater displacement of sediments with age and depth along the listric glide fault plane) has created a downthrown rollover into the faults. The overburden is heavily faulted above the reservoir by a series of synthetic and antithetic faults (Figure 1).

The main reservoir in this field is the Siph (D) 120/122 sand, which has a maximum gross pay thickness of 500 feet. At discovery, the reservoir pressure was approximately 12000 psia at a datum depth of 13100 feet subsea, with a temperature at the datum of 295°F. Reservoir rock varies from poorly consolidated to well cemented, fine-grained sandstone with petrophysical properties typical of Gulf Coast reservoirs: porosities of 20 to 32%, permeabilities of 10 to 2843 md, and pore volume compressibilities of 4 to 17 microsips (varying with the porosity of the rock and the stage of depletion).

The overburden above the reservoir is also highly overpressured. The top of the overpressure occurs at an approximate depth of 8500 feet subsea, and generally parallels stratigraphy. The reservoir pressure at the crest of the structure is interpreted to coincide with the seal capacity of the overlaying shale, limited either by the fracture gradient or capillary sealing capacity (Figure 2).

During the past 16 years of production (1986–2002), reservoir pressure has declined from the initial 12000 psi to the current 2700 psi (Figure 3), and all the 17 wells that were producing the Siph (D) 120/122 sand (8 wells from Phase I and 9 wells from Phase II) have experienced some form of well failure (sand production or sustained casing pressure) or casing damage (casing offset, tight spots, parted and/or collapsed casing in both overburden and reservoir). Since 2001, technology specialists have worked with the Matagorda Island asset subsurface team to investigate the causes and formulate a forward strategy. A suite of studies has been conducted aimed at assessing the root cause of existing well failure/casing damage and predicting the well life of existing key wells and new drills in Phase III. This paper is a summary of the key finding from these studies.

Well Failure History
Phase I Development Wells

Initial development of the Siph (D) 120/122 reservoir occurred between 1982 and 1985 with the drilling of 6 wells from the MI622 C platform (wells C-1 through C-6). The completion type for all of the initial wells was cased and perforated. Two additional wells, the E-1 and MI635#1, were later added at remote locations with cased hole gravel pack completions. Early production from Siph (D) 120/122 reservoir was maintained at about 150MMcfd. Producing rates for each well were generally limited by sand production. All the wells producing Siph (D) 120/122 were in good pressure communication. The annual reservoir pressure drop has been about 500psi (Fig. 3).

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