This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
When frac-packing near contacts with undesirable fluids, fracture height growth must be minimized. Likewise, when fracturing relatively low-permeability gas sands, the required tip-screenout event may be difficult to obtain due to excessive fluid efficiency leading to excessive fracture growth. One technique to address both of these problems is the use of non-viscosified brine as a fracturing fluid (i.e., water-fracturing). Water-fracturing limits fracture growth due to its high leakoff, and allows pad volumes to be minimized because proppant concentrations are maintained at low levels throughout the treatment. However, the technique does suffer in that the proppant carrying ability of water does not allow proppant concentration to exceed about 2.5–3 PPA. This constraint can lead to reduced near-wellbore fracture conductivity as compared to a properly executed frac-pack using crosslinked fluids. A fluid that has good leakoff and good proppant carrying capacity will provide the opportunity to bridge the gap between water-fracturing and crosslinked gel frac-pack operations. A new generation visco-elastic surfactant (VES) fluid provides this opportunity. The Barbara field in the Adriatic Sea is a shallow dry gas field and formation sand has to be controlled with gravel pack. It was originally completed with standard gravel packing procedures, which were migrated to water-fracturing techniques during the mid-1990's. While this completion method proved successful, it was desired to increase fracture conductivity while continuing to control fracture geometry. The use of a low-concentration VES fluid allowed such optimization of the frac-pack process, leading to significant productivity improvements. This paper reviews the evolution of completion techniques in the Barbara field that has led to these productivity improvements. Introduction The Barbara field is situated in the Adriatic offshore area approximately 18 miles (30 km) from the coast. The reservoir sands are composed of sediments of the Asti formation, which were deposited in the Pleistocene period in a turbidite environment. The cap rock is formed by several argillaceous intercalations. Methane gas-bearing strata are found in the sand. The sequence starts with the layer "A" and ends with the layer "U", from 3510 to 4528 ft (1070 to 1380 m) TVD. The permeability ranges from a minimum of 5–10 mD to a maximum of 500–600 mD. Although of fairly low permeability, the sands are considered to be highly unconsolidated, and require sand control. To help ensure maximum productivity from these sands, it was realized early that high-quality gravel packing techniques are required. To achieve this goal, several gravel placement techniques have been tried. First, openhole gravel packs were successful in obtaining highly efficient completions; however, this completion technique was deemed unsuitable while individually completing multiple zones with individual water contacts. Unfortunately, when the change was made to inside casing gravel packs, productivity suffered. The decision was then made to introduce frac-packing to the Barbara field. Over a period of about eight years, the frac-packing techniques have advanced.
This article presents the development of a computational tool to guide horizontal gravel-pack design for long horizontal offshore wells. Mechanistic model hypotheses, experimentation at a largescale flow loop, and software development are detailed. The computer simulation results are then compared with field data collected in the Campos basin operations, offshore Brazil. A discussion on design alternatives for a long horizontal well at low fracturegradient formations is presented. This discussion includes a sensibility analysis on screen eccentricity, open and closed blowoutpreventer (BOP) configurations, and alpha (alone) vs. alpha plus beta wave displacement options.
The Etame oil reservoir is an ovalshaped, low-relief structure with a moderate aquifer drive. To maximize ultimate field recovery, the ET-6H well was drilled with a horizontal lateral positioned to traverse the reservoir near the structural crest and to be within the Upper Gamba sandstone throughout its length. The Gamba sandstone averages 45 ft in thickness and overlies a significant angular unconformity. The subcropping Dentale-aged sandstones and interbedded shales below this unconformity have dips to 12°. The oil column of approximately 170 ft extends below this unconformity. Previous wells in the field were completed using openhole horizontal gravel packs (OHGPs) and have experienced excellent sand-control performance. However, OHGPs offer no protection against early water breakthrough. The Gamba sand averages 30% porosity with a permeability range of 1 to 3 darcies. The Dentale sands are much more variable, with porosities of 18 to 30% and a permeability range of 50 to 1,000 md. Thus, if a portion of the lateral is situated immediately above a high-permeability Dentale sand, the well will be at risk of early water breakthrough and subsequent reduced recovery if it is completed with a standard OHGP.The operator gravel packed the ET-6H well and used a system that provides a near-uniform inflow profile along the entire lateral length to protect against early water breakthrough. The gravel packing of inflow-control devices (ICDs) presented some unique challenges because of their differences from standard sandcontrol screens.This paper describes the implementation of the world's first gravel packed inflow-control completion, including: ICD selection process, gravel-pack design, data from the gravel-pack operation, and resulting well performance.
As operating conditions become more severe, and the costs associated with well failure escalate, the need for effective sand control increases. However, in a time of tightening economic constraints, the need to control costs also drives decision making. In this time of apparently conflicting concerns, the industry has responded with a move away from traditional Sand Control to what can be more properly termed Sand Management. Several projects described in the literature are concerned with a particular aspect of Sand Management. Whether it is a description of predictive modeling, preventing sand production through rate control and/or selective perforating, improved sand control through advanced completion practices of frac-pack or horizontal well gravel packing, or the latest in expandable screen products, these studies have focused on one (or perhaps two) aspects of an overall Sand Management project. To fully grasp the benefit of this new completion paradigm, we must stop looking at well design with a preconceived answer in mind. Rather, all aspects of Sand Management must be considered when making field development decisions. It is the goal of this paper to bring the best from previous studies together to provide a solid review of available Sand Management techniques. However, since all decisions have either positive or negative consequences, this paper also reviews the economic and operational concerns associated with these decisions. An understanding of how initial decisions may impact future options will assist in enhancing our ability to optimize completion type selection. Introduction Sand Management, the term generally brings to mind processes that must be put into place that will provide for the co-production of formation sand and reservoir fluids. However, in recent years the term has grown to mean considerably more. Sand management is now applied to all technologies, processes, and completion techniques that are meant to address the issue of producing fluids from weak formations. These technologies include computer models to predict sand production tendencies, field techniques to prevent formation failure, downhole equipment to prevent failed formation material from entering the wellbore, best practices for installing completion to maximize productivity, monitoring techniques to determine when sand is produced, surface equipment for handling produced sand, and workover equipment for performing remedial operations. From this list, it becomes very clear that many things must be considered if a truly optimized sand management plan is to be enacted for a project. To optimize a project it must first be determined what is to be optimized. There is a tendency, when making completion design decisions to focus on either initial cost or initial productivity. While this approach provides some significant short-term benefits, it does not address the long-term goals of most producing companies. Overall the goal that is sought is to maximize the profitability of a project. It is true that a big piece of this equation will be initial cost and initial productivity; however, these are not the only parameters that must be considered. Rather, to maximize the profitability of a project, a balance must be achieved between installation cost, initial and long term productivity, operating costs, and operational risk. Time savings established during initial completion must be balanced against costs associated with future workover operations and deferred production. Background When the above definition of sand management is adopted, it becomes very obvious that many papers have been written on portions of this subject area. To assist in categorizing these previous publications, the following subcategories can be offered:Prediction: a. Theoretical sand failure models b. Techniques for rock property determinations c. Evaluation of parameters affecting formation strength over productive life of reservoir.Prevention: a. Maximum sand-free rate determination b. Maximum allowable drawdown c. Co-production of oil and sand to maximize productivity d. Formation stabilization
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