Leen Weijers

Understanding hydraulic fracture growth : Tricky but not hopeless

Hydraulic fracturing has proven to be a fruitful well stimulation technique in an ever-increasing range of environments. Application has spread from the original targel of enhancing production rates from low permeability reservoirs to fracturing of poorly consolidated high perm reservoirs, fracturing of horizontal and deviated wellbores, fracturing of unconventional (often naturally fractured) reservoirs, fracturing for waste disposal, etc. While significant progress has been made in engineering hydraulic fracturing treatments, we are still often humbled and alarmed by the apparent complexity of the process This paper does not present the answer to this complex problem. Instead it attempts to shed some light on areas where we must be careful with our assumptions. This paper presents examples of measuring (inferring) hydraulic fracture growth in a number of different environments. For each example we discuss the implications of the observed fracture growth. For example, how accurate were the fracture model predictions How effective is the current completion / fracturing strategy in achieving the design goals. What are we learning about the factors or mechanisms that govern hydraulic fracture growth? How can these new insights aid production enhancement? While most of the direct observations of hydraulic fracture growth are from downhole-tilt fracture mapping, data from many additional diagnostics are also included (post-frac logging, production response, intersections with offset wells microseismic mapping, etc). Perhaps the most surprising observation is the observed range of fracture height growth: spanning from well-contained fractures in the absence of significant formation stress barriers, to extremely uncontained fracture height growth. Observations of fracture width, length. and asymmetry will also be presented and discussed.

Hydraulic fracture reorientation Does it occur? Does it matter?

Hydraulic fracture growth, the dominant method of well stimulation, is controlled by the in-situ reservoir stress state. The in-situ stress state controls hydraulic fracture orientation and, for the most part, the created hydraulic fracture geometry. In-situ stress evolves over the geologic history of a reservoir, leaving footprints of this evolution such as natural fractures and anisotropic permeability. However, on a vastly different time scale of months or even hours, the reservoir stress state can be dramatically altered via fluid production and/or injection. These man-made poroelastic stress perturbations alter the stress magnitude and sometimes even the stress orientation, inducing a change in hydraulic fracture orientation that has been observed on refracture treatments. Fracture reorientation has also been observed on fracture treatments of new infill development wells in mature fields, and is regularly observed on cyclic injection operations in disposal wells.

The Value Proposition for Applying Advanced Completion and Stimulation Designs to the Bakken Central Basin

The Bakken boom in North Dakota is currently focused on the Central Basin area where around half of the drilling rigs in North Dakota are now operating. What makes this area different compared to previous areas of Bakken development is that there is only minor structural variation and significantly less naturally induced fracturing as compared to the higher permeability rock facies that exist in the sub-reservoirs of earlier Bakken development such as at the Elm Coulee field in Montana or the Sanish and Parshall fields in North Dakota. As a consequence, the role of the well’s completion and stimulation design has a greater significance and impact on well productivity and ultimate recovery. Different companies have taken very different approaches to well design using either plug and perf or ball and sleeve completions, and a variety of fracture designs with slickwater, hybrid or cross-linked gel fluids and a variety of proppants from 100% natural sand to 100% ceramics. As a consequence, it is not uncommon for different operators to have over a 2 million dollar difference in their AFE’s solely because of the differences in approach to the well’s completion and stimulation design. The authors have chosen to apply “advanced completion and stimulation designs” which are designed to maximize the reservoir contact area (slickwater and plug and perf) and optimize the conductivity (ceramic proppant at relatively high volumes). In order to benchmark performance of its completion and stimulation program the authors in 2010 developed a production and completion database of all wells completed in the Central Basin using publicly available information from the North Dakota Industrial Commission’s records augmented by additional completions information obtained directly from the operators. From an initial dataset of ~30 wells the database has been updated monthly and has now grown to over 1100 wells in the Central Basin from 28 operators. Benchmarking of completion performance has been performed using the above database together with a Petra geological database developed from all publicly available logs in the Central Basin (~500 vertical wells which had been drilled and logged prior to the first Bakken horizontal well). Benchmarking of performance is somewhat subjective in the Bakken (as well as most reservoirs) due to variations in reservoir quality. Without geological input (reservoir quality), the acquired data were too scattered to achieve meaningful correlations to completion methods unless the area was limited to ensure similar reservoir quality for the wells being evaluated. By narrowing the analysis to very limited areas; this also reduced the input as to the number and type of completion methods being compared. Multivariate analysis methods, that included geological input, were used to benchmark performance over most of the Williston Central Basin, allowing comparison of the varied completion methods for 28 operators and over a thousand wells. Using multiple parameters an excellent correlation for completion methodology versus reservoir quality was obtained. While early analysis focused on 30, 60 and 90-day cumulative production; in the past year there have been enough wells to generate performance metrics based on 180 and 365-day cumulative production since over 600 wells have now been on production for at least a year.

Breaking Up is Hard to Do: Creating Hydraulic Fracture Complexity in the Bakken Central Basin

The Bakken drilling boom in North Dakota has seen a frenzy of activity over the past several years as operators sought to hold acreage and create value with the drill bit. This has been particularly true in the Central Basin portion of the Williston Basin where initial wells drilled prior to 2008 were uneconomic. However, advances in completion technology caused such a fundamental shift in economics that the whole Central Basin area of over 2500 square miles has been opened to economic development with ~100 rigs currently drilling in the region. The most fundamental change in completion design has been the incorporation of “high-intensity” multi-stage fracturing. What makes Bakken completion design fundamentally different from recent shale gas developments has been the widespread use of uncemented liners with external packers in the open-hole lateral in order to create the multi-stage zonal isolation. As operators have advanced the application of multi-stage completion techniques there has been a wide variety of completion equipment used and stimulation designs that have been pumped. This operator decided to employ a completion design that comprised: (i) An open-hole “uncemented” liner section; (ii) Annular zonal isolation created by swell packers; (iii) The use of “plug and perf” technology to individually open successive zones to stimulation; (iv) The pumping of slickwater fracture treatment fluids at high rate; (v) The use of high-quality ceramic proppant to generate the required fracture conductivity. Production data are presented from 58 wells in which this completion and stimulation design has been conducted, which show that the use of this approach has resulted in well performance that is 25-45% superior to any other Bakken completion technique. Geology The Bakken Formation (highlighted in red in Figure 1) is located within the Williston Basin, which spans southern Saskatchewan and Manitoba in Canada as well as North Dakota and Montana in the United States. The basin was formed as a subtle downwarping between the Superior Craton to the northeast and the Wyoming Craton to the southwest. The Williston Basin is a gently dipping basin with very little structural deformation, with the exception of a small number of structural features including the Nesson Anticline and the Cedar Creek Anticline, as shown in Figure 1. Figure 1—Location of the Williston Basin.