John McLennan

Poroelasticity considerations in in situ stress determination by hydraulic fracturing

Abstract The impact of poroelasticity effects on the fracture closure pressure p foc , breakdown pressure p b , and reopening pressure p re , and their influence on the interpretation of in situ stress are reviewed in this paper. Using solutions of a borehole and a fracture in an infinite poroelastic domain, it is shown that: (i) the breakdown pressure can be significantly higher than the elastic prediction (valid for impermeable rock); and (ii) the fracture closure pressure is generally larger than the far-field normal stress, the difference being dependent on the injection time.

A Poroelastic PKN Hydraulic Fracture Model Based on an Explicit Moving Mesh Algorithm

Description of the mathematical formulation of a Perkins-Kern-Nordgren (PKN) fracture model, that accounts for the existence of poroelastic effects in the reservoir. The poroelastic effects, induced by leak-off of the fracturing fluid, are treated in a manner consistent with the basic assumptions of the PKN model, by means of a transient influence function. Numerical simulation with this model indicates that poroelastic processes could be responsible for a significant increase of the treatment pressure, but that they have virtually no influence on the fracture length and fracture width

The Role of Natural Fractures in Shale Gas Production

Natural fractures seem to be ubiquitous in shale gas plays. It is often said that their presence is one of the most critical factors in defining an economic or prospective shale gas play. Many investigators have presumed that open natural fractures are critical to gas production from deeper plays such as the Barnett, as they are for shallower gas shales such as the Dev‐ onian shales of the northeastern US and for coal bed methane plays. A common view on production mechanisms in shales is “because the formations are so tight gas can be pro‐ duced only when extensive networks of natural fractures exist” [6]. However, there is now a growing body of evidence that any natural fractures that do exist may well be filled with calcite or other minerals and it has even been suggested that open natural fractures would in fact be detrimental to Barnett shale gas production [9]. Commercial exploitation of low mobility gas reservoirs has been improved with multi-stage hydraulic fracturing of long horizontal wells. Favorable results have been associated with large fracture surface area in contact with the shale matrix and it is here that the role of natu‐ ral fractures is assumed to be critical. For largely economic reasons hydraulic fracturing for increasing production from shale gas reservoirs is often carried out using large volumes of slickwater injected at pressures/rates high enough to create and propagate extensive hy‐ draulic fracture systems. The fracture systems are often complex, due essentially to intersec‐ tion of the hydraulic fractures with the natural fracture network. After hydraulic fracturing operations the injected water is flowed back. Typically, only a small percentage (on the or‐ der of 20 to 40%) is recovered. In this paper we investigate the role played by natural fractures in the gas production proc‐ ess. By applying a new model of the production process to data from many shale gas wells across a number of shale plays in North America, we can for the first time begin to sort out assertion from inference in the role that these fractures play. Specifically, we are able to esti‐

Completions and stimulations for coalbed methane wells

Amoco is producing coalbed methane from several hundred wells in both San Juan and Warrior basins. These wells were completed/stimulated in one of two ways : (1) open hole cavity completions, (2) hydraulic fracture stimulations through perforations in casing. Cavity operations are described, and new data from several cavity completions is presented and analyzed. The latest geomechanics modeling of the formation of cavities in coalbeds is presented. The model allows the growth of a cavity as tensile failure occurs, and computes increases in permeability in a stress-relief zone that extends tens of feet from the well. Critical parameters are given for the success of cavity completions. A pulse interference analysis is discussed : as well as interwell permeability, this can provide information on stress-dependent permeability. Finally, some wells which were originally cavitated did not perform up to expectation, and have been recavitated with remarkable success - these are also examined. Amoco has tried several different kinds of hydraulic fracturing treatments. Results of comparisons between foam fracture, slick water fracture, and gel fracture treatments are presented. Statistical comparisons are given for regions outside of the fairway zone in the San Juan Basin. In the Warrior Basin, water fracture treatments with and without sand have been compared. Lastly, foamed water cleanouts, without sand, have been deployed, and their success is reviewed.

How Instantaneous are Instantaneous Shut-In Pressures?

Shut-in pressure is regarded conventionally as a static pressure-equilibrium condition existing between a slightly open fracture and the in situ stress regime. Several techniques for determination of this pressure level, from pressure-time records, have been presented. This work reviews the various definitions and mechanisms for shut-in pressures and critically evaluates the general validity of this concept as a stress parameter indicator. It also outlines the factors which may affect the positive identification of a distinct shut-in (i.e., leakoff, nonuniform fracture azimuth, presence and distribution of proppant and fracture length). The study also provides an alternate interpretation technique, allowing for discrimination between effects of this nature and the existing in situ stress field. The alternate technique is corroborated by precise situations, including micro-hydraulic fracturing and hydraulic fracturing treatments. 35 references.

Cavity-like completions in weak sands

This study is about when, where, and how to implement an advanced completion technique, basec on deliberate sand production, in order to induce cavities that increase productivity of a well (a cavity can be a void, or an cohanced perm zone of disaggregated sand). The concept spans the spectrum of well life, from a cavity as the initial completion, to managing sand flowback in mature wells. Folds-of-increase (FOI) in the range 3-20 have been found in field applications. This compares with FOI of 2-5 after hydraulic fracturing In certain field cases, sand does stop coming into the well as the cavity stabilizes. A strong enough caprock (overburden material) is a key to the success of cavity completions in some unconsolidated formations in the field Two kinds of laboratory tests have been conducted: (1) centrifuge tests in unconsolidated sands with low stresses, (2) large block tests in weakly consolidated sands, with more realistic stresses. In both cases, allowing sand to flow increased the productivity of the well by several fold, and the cavity geometries provided insights into what may happen in the field. The work has also included evaluations of subsidence and casing stability, due to sand production. Also, a model has been created to optimize a cavity completion by calculating the productivity increase (P) stability of cavity, and sand disposal costs, all as a function of volume of sand removed. The results herein have implications for other business areas: eg, sand management; increasing injectivity for injection wells; and underbalanced drilling, perforating, surging applications.

How Can Sand Production Yield a Several-Fold Increase in Productivity: Experimental and Field Data

Centrifuge physical model tests were performed to study the mode of failure during sand production and its concomitant impact on the productivity index. The tests simulated seepage-induced failure around a vertical well. Results indicate that in the presence of a competent cap rock (1) sand production results in the formation of a cone-shaped enlarged cavity; (2) surface subsidence of the reservoir due to loss of sand mass which may result in opening of flow channels under the cap rock; (3) for a given wellbore pressure, sand production ceases once the enlarged cavity lowers the flowrate to sub-critical level; (4) flow becomes diverted towards the upper perfs where the cavity radius is largest; (5) flow rate increase varies between 5 to 50 times depending on whether the mode and volume of sanding is sufficient to result in the formation of flow channels. The study performed shows that (1) the location of perfs affects the mode and magnitude of sand production and the concomitant productivity, and (2) long-term productivity can be improved through managed sand production. Presence of a competent cap rock is the key for maximizing the productivity via sanding. These findings are consistent with some field cases where extraordinary increases in production were noted as a result of sanding. Sand production, if properly managed, can reduce the completion costs (e.g., by omitting or delaying installation of sand exclusion measures) and improve the long term productivity by removing the skin damage and also through creating voids and zones of higher porosity around the well and under the caprock.

ISRM Suggested Method for Uniaxial-Strain Compressibility Testing for Reservoir Geomechanics

Please send any written comments on this ISRM Suggested Method to Prof. Resat Ulusay, President of the ISRM Commission on Testing Methods, Hacettepe University, Department of Geological Engineering, 06800 Beytepe, Ankara, Turkey at resat@hacettepe.edu.tr .

The Mancos Formation: An Evaluation of the Interaction of Geological Conditions, Treatment Characteristics and Production

In general, the Mancos Formation is an underpressured sequence composed of intimately interbedded siltstones and shales in a relatively faulted geologic environment. Apparently sporadic production trends from the Mancos Formation in northwestern Colorado led to an intensive evaluation program. This encompassed laboratory determination of the mechanical and fluid transport properties of the formation as well as evaluation of treatment and production records. Production trends were compared with known geological conditions as well as stimulation procedures. Mechanisms for the variability in production and the local effectiveness of treatments are outlined. General procedural approaches for optimum recovery are discussed. These procedures include resource determination guidelines and general stimulation guidelines.

The Fate of Injected Water in Shale Formations

It is well known that only about a third of water injected for hydraulic fracturing of shales is recovered. It is important to understand the fate of this injected water. The amount of water infiltrating the matrix is determined by a number of parameters such as the pressure differ‐ ential between the fracture and the matrix, the capillary pressure relationships in the frac‐ tures and in the matrix and other petrophysical properties of the formation. In this paper, we provide a breakdown for the various possible water losses depending on the reservoir, fracture and operating parameters. A set of capillary pressure relationships for the forma‐ tion were first created based on the basic mineralogy and the total organic carbon (TOC) content. Fracture capillary pressure also changed depending on the concentrations and types of proppants in the fractures. Two basic end members can be defined – silicistic and dolomitic with different amounts of TOC. The capillary pressure relationships ranged from oil wet, neutral to water wet. Different porosity and permeability combinations were also examined. Amounts of water relative to the total amount injected that would infiltrate the formation were compiled as the operating conditions (pressures) and formation properties changed. This calculation shows that the infiltration due to the various phenomena are not sufficient to account for the water losses if the formations are strongly oil wet. In addition, situations where water blockages occur due to these multiphase flow effects were identified and the loss of productivity due to this phenomenon was quantified both for gas and for oil production. The study was conducted using a discrete-fracture network simulator devel‐ oped at the University of Utah. A realistic (non-orthogonal) representation of a complex fracture network was employed in the study. Realistic representation of distribution and re‐ tention of these aqueous fracturing fluids is essential for optimizing hydraulic fracturing treatment volumes.