This paper will evaluate the efficiencies of completion methods in a South Texas field utilizing the latest techniques in post fracture production analysis.Stimulation effectiveness for each frac stage in ten multi-zone wells is evaluated. Effective values for reservoir and fracture parameters including porosity, permeability, propped fracture half-length, fracture conductivity and fracture face skin will be derived using production analysis techniques and will be compared for the different completion methods employed.The holistic model will incorporate the geological, petro-physical properties of the formation and production logging data. Actual stimulation and production data from ten wells in the same area are used in this analysis. Five of the wells were completed in single-stage fracture stimulation across multiple perforated intervals.Five wells were completed with two-stage fracture stimulations across multiple perforated intervals.The multiple layer fracturing technique was utilized in all wells. The study will derive the effective reservoir and fracture parameters using production allocation for each interval in the multiple interval wells. This paper will compare the different completion techniques using this methodology and will discuss a predictive model for future stimulation work in this area.This methodology will also help in identifying under-stimulated zones in existing wells that may be candidates for re-fracturing. Introduction The wells included in the study are part of the Wilcox Lobo Trend located in Zapata County in South Texas.The Wilcox (Lobo) trend in Webb and Zapata counties is a series of geopressured, low permeability sands with an average depth from 5,000 to 12,000 ft (1,525 to 3,660 m).The Lobo section consists of a sequence of stacked Paleocene age sands and shales overlain by the Lower Wilcox shale of Eocene Age.Extensive faulting, present in the Lobo section, has resulted in a slump complex of rotated fault blocks.The Lobo trend extends from Webb and Zapata counties to the south and west into Mexico (Figure 1).Effective permeabilities are less than 0.1 md.Implementing an effective hydraulic fracture treatment and an evaluation process for stimulation effectiveness are requirements to economically produce the low permeability sands in the Lobo trend. The wells presented here are nearby offset wells in the Lobo field (Figure 2). These wells were completed in 2003.The target intervals in these wells are primarily three zones.All the wells were fractured with similar fracturing fluids, intermediate strength proppants and aggressive breaker schedules utilizing multiple layer fracturing techniques. Background Extensive work has been conducted around fracture treatment design and evaluation of wells with multiple zones with most of the work focused on the use of limited entry techniques to effectively place proppant across multiple zones [1,2,3,4].The limited entry technique utilizes perforation friction to divert designed fluid and proppant volumes into multiple zones.This method is utilized when the economics do not justify multiple stages or when multiple stages cannot be placed effectively[5].This technique has been successfully implemented in the Lobo field in numerous wells.The success comes from applying the formation evaluation and log analysis into a fracture modeling process, and from the use of limited entry design guidelines [6,7].Tracer surveys and production logs were obtained after numerous stimulation treatments to develop these guidelines.However, tracer surveys provide an estimate of the fracture height and production logs provide contributions from each zone in a snapshot of time.
A mature tight gas field in North Louisiana that experienced dwindling performance and erratic predictability spurred the creation of an alternative technology that boosted production rates and minimized completion costs. An average production rate uplift of 108% shown on three wells resulted from modifications to mud logging operations; careful interpretation and integration of data; and the addition of new, proprietary transforms. The resultant technology provided a variety of useful information with little or no additional cost or mechanical risk. When conventional wireline technology proved both technically and economically unsuccessful, an alternative technology was needed to determine reservoir pressure from mud log gas with sufficient resolution to support zone selection, completion design, and the identification of bypassed pay. This document describes the proprietary technology and a variety of specific applications employed by the development team. Production logs and conventional pressure measurements demonstrate the performance increases achieved by incorporating this technology into the development program. Introduction Ada field in North Louisiana contains an abundance of stacked, poorly connected, fluvial/shallow marine reservoirs that are difficult to correlate from well to well and predominantly irresolvable with available 1993 vintage 3D seismic data. Production began in mid 1960. Currently, the numerous individual reservoirs show pressure gradients ranging from a fully depleted 0.06 psi/ft to an original pressure of 0.54 psi/ft. Limited-entry fracture stimulation and co-mingling of production meant that loss of production to thieving by depleted reservoirs and stimulation effectiveness were ever present limitations to individual well performance. After going through multiple stages of down-spacing, the field was undergoing a hybrid down-spacing to approximately 20 acres per well, based on detailed mapping of extensive faulting that further compartmentalized the field. A typical well in this field encounters 600 feet gross sand (300 feet net reservoir) comprised of 20 to 60 individual sandstone layers. Sandstone thicknesses range from 3 to 50 feet. Typical reservoirs have porosities of 4% to 10% with permeabilities of 0.001 to 0.1 mD. Wells initially produce dry gas at a rate of 2 MMcf/d with EUR's in the range of 1 Bcf. Formation pressure testing with current wireline technology in up to 60 zones per well proved to be uneconomic. A program similar to that described by Schrooten, et al.1 was used, but a variety of difficulties resulted in an undesirable cost/success ratio. Wireline pressure tools were also proven ineffective in the majority of their applications due to (1) low permeabilities requiring impractical lengths of time on station; (2) supercharging producing unrepresentatively high pressures; in addition to (3) tool-sticking problems that frequently resulted in fishing operations. The new technology was based on the common drilling experience that showed relative pressure between the drilling and formation fluids had a marked effect on the magnitude of gas show observed at the surface. The apparently robust nature of this gas-reducing effect led the Development and Technology teams to pursue a characterization of the fundamentals controlling it. Conversion of this phenomenon into a quantifying tool required reconciling discrepancies among uncommon depth references, inherent error, and vertical resolution. By applying the combined gas laws (relating gas volumes, pressures and temperatures) to basic elements from drilling engineering, reservoir engineering, mud logging, and petrophysics, the team transformed the drilling and logging operations themselves into a single, large-scale measurement apparatus. The new technology for Geobaric Thermal Volume Analysis (GTVA) exploits the gas-reducing effect of increased relative pressure (i.e. increased over-balance) to (1) quantify pressure, (2) quantify formation gas content, and/or (3) predict mud cut in gas-bearing formations.
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