Green Canyon

This paper presents the results of an integrated laboratory and numerical modelling study on the effect of wellbore deviation and wellbore azimuth on fracture propagation in poorly consolidated sandstone formations. The goal of this project was to develop an understanding of how fractures would transition from single planar fractures to non-planar transverse fractures for fields in the deep-water Gulf of Mexico.

The foundation of this work was over 40 fracturing laboratory tests to measure fracture propagation geometries for a range of well deviations, differential horizontal stresses and rock strength. The samples tested were from three outcrops with unconfined compressive strength (UCS) values ranging from 300 - 1000 psi. For boreholes having low deviation angles and small differential stresses a vertical single planar fracture was created, aligned with the wellbore, as expected. As the well trajectory and stress contrast increased the fractures became more complex, with transverse turning fractures no-longer aligned with the wellbore.

These laboratory results were used to develop and calibrate a new fully-3D finite element model that predicts non-planar fracture growth. The model matches the details of the laboratory tests, including the transition from planar vertical to non-planar transverse fractures as the well deviation, azimuth and stress differentials increase. After initial model development and calibration was complete a model of a complex case was run before showing any experimental results to the modellers. The model successfully predicted the transverse non-planar results found in the laboratory; this gave us increased confidence in the model as a predictive tool.

This work has now been applied with excellent success to four deepwater fields. We have recommended changes in maximum well deviations, performed post-job analyses on wells that had high deviations, and have increased our understanding of the impact of layered formations on fracture growth in these fields.

Summary

Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a very short time period, initiating a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture closure pressure, and the fracture pseudolinear-flow period leads to the initial reservoir pressure.

In most tests, wellhead pressure (WHP) measurements are used because of cost considerations. A wellbore heat transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (p_fb) during the injection period. As expected, the p_fb always turns out to be higher than the fracture closure pressure (p_fc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained.

A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than its transverse counterpart.

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Deepwater Drilling and Completions Conference held in Galveston, Texas, USA, 20-21 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Frac-packing is a completion technique that merges two distinct processes: Hydraulic fracturing and gravel packing. The main challenge of a frac-pack completion is the successful creation of high conductivity fractures using the tip-screen out technique and placement of proppant within those fractures and the annulus between the screen and wellbore. This is further compounded by having to do so in an ultra high permeability environment, where high fluid leak-off rates are evident. Since 1997, job data from more than 600 frac-packing operations worldwide have been compiled into a database. Also summarized are engineering implementations and challenges, best practices, and lessons learned. Essential frac-pack design parameters attained from the step-rate-test (SRT) and mini-frac test are evaluated. These include bottom hole pressure, rock closure time and fracturing fluid efficiency. Down hole pressure and temperature are also discussed because of their importance to the post completion efficiency evaluation and fracturing fluid optimization phase. Worldwide case histories are provided demonstrating how to deploy different frac-packing systems and pack the wellbore under extreme conditions with improved packing efficiency and a higher chance of success.

Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a very short time period, initiating a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture closure pressure, and the fracture pseudolinear-flow period leads to the initial reservoir pressure.

In most tests, wellhead pressure (WHP) measurements are used because of cost considerations. A wellbore heat transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pfb) during the injection period. As expected, the pfb always turns out to be higher than the fracture closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained.

A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than its transverse counterpart.

Much has been written about the deepwater Lower Tertiary Wilcox trend in the Gulf of Mexico, which spans hundreds of miles from Alaminos Canyon to Keathley Canyon to Walker Ridge (as well as adjacent areas). The estimated ultimate recoverable oil from these reservoirs is significant: 3 to 15 billion barrels. However, significant technical and reservoir challenges remain because of the water depth (typically greater than 5,000 ft), reservoir depth (typically greater than 20,000
to 30,000 ft below the mud line (BML)), and high pressures (greater than 20,000 psi bottomhole pressure (BHP)). Combining these issues with the thick, low permeability reservoir intervals (more than 1,000 ft thick in the tens of mD) requires new tools as well as new planning and optimization methods.

These new planning tools require system-wide (holistic) integration across multiple domains and completion software applications to produce a truly optimized completion. This type of integration is provided by an automated software workflow. Previous papers have provided details about the benefits derived from the automation of operations, engineering, and production workflows in general. Lower Tertiary Wilcox reservoirs were deemed good candidates by a major service
company to implement the automated workflow concept, given the reservoirs' low productivity index (PI), high-cost wells, high pressure/high temperature (HPHT) technical challenges, and production uncertainty.

This specific workflow seeks to optimize hydraulic fracture design within Lower Tertiary Wilcox reservoirs by stipulating the maximum net present value (NPV) that satisfies all well, completion, and reservoir constraints. Hydraulic fracture design is an example of what is largely a manual process that requires interaction with several software applications to obtain fracture geometry, production constraints, production sensitivity criteria, and NPV scenarios. When the goal is an optimized
fracture design, the process is especially arduous because it requires iterative interactions with reservoir simulators, nodal programs, economics models, well tubular design systems, and stimulation design tools to arrive at a suitable design.

Enabling coupled simulations technology, this fracture workflow provides a unique holistic combination of tools, which are linked to reflect the actual economic values.

Lower Tertiary Overview
The deepwater Lower Tertiary play is considered to be an extension of the established onshore Lower Tertiary Wilcox trend along the Gulf Coast in south Texas and Louisiana. The Lower Tertiary Wilcox play on land is primarily a gas play. In the deepwater Gulf of Mexico (GOM), the play targets the subsalt Paleogene formation, specifically Paleocene and Eocene, along the Sigsbee Escarpment in the Perdido and Mississippi Fan fold belts (Lewis et al. 2007). The trend is located 175 miles offshore GOM; it is approximately 80 miles wide by 300 miles long. Most of the activity in this trend is focused in Alaminos Canyon, Keathley Canyon, and Walker Ridge.

The trend is generally characterized by older sediments with lower porosities, ultra-deep water depths, and high BHPs. For this trend, water depths range from 4,000 to 10,000 ft; the target reservoirs depths have ranged from 25,000 to 35,000 ft. The reservoirs are thick, typically exceeding 1,000 ft gross, with high sand content (Halliburton 2011).

The BHPs of Lower Tertiary wells routinely exceed 20,000 psi; bottomhole temperatures (BHTs) range from 230° F to 300° F. Permeability and porosity values generally range from 1 to 50 mD, with an average of 10 mD; porosity values range from 14 to 20%, with an average of 17%. There is a wide range of PVT properties. The oil generally ranges from 22° to 41° API, with a low gas/oil ratio (GOR), and variable viscosity (Rains et al. 2007).