This paper shows a comparison of dual-array microseismic maps with single-well maps for horizontal wells in the Barnett shale. Results from two test cases showing gel and water fracturing maps are given and compared with initial production. Dual-array mapping provides for a much larger areal coverage and increased accuracy when accurate bottomhole locations and velocity structure are available, but do have trade-offs that need to be considered.

Hydraulic fracturing is key to the economic success of many oil and gas fields around the world and has improved production in low permeability reservoirs for more than 50 years. Successful stimulations are engineered to place the proper type and volume of slurry based on estimating the dimensions of the optimal fracture to be created in a specific wellbore. Several commonly used technologies are available which determine important fracture parameters such as fracture dimensions, fracture orientation, fracture conductivity and proppant placement effectiveness. Fracture models are today's most widely used tool to predict the optimal frac geometry based on conditional inputs such as closure stress, pore pressure, permeability, fluid saturation and numerous other mechanical and petrophysical properties of the reservoir. In many cases, these parameters are based on assumptions rather than hard data, and incorrect assumptions then lead to sub-optimal stimulation results.

In recent years there have been numerous advances in fracture mapping/diagnostic technologies. This paper details the state-of-the-art in applying both conventional and advanced technologies to better understand hydraulic fracturing and improve treatment designs. The initial portion of the paper describes the application and limitations of various diagnostic tools and methods, including well testing, net pressure analysis (fracture modeling), techniques that employ open-hole & cased-hole logs, surface & downhole tilt fracture mapping, microseismic fracture mapping, and production data analysis. The bulk of the paper is dedicated to case histories that illustrate the application of these various fracture diagnostic technologies. The case histories include examples of how several fracture diagnostics can be used in concert to provide more reliable estimates of fracture dimensions and allow better economic decisions.

Hydraulic fracturing has proven to be a fruitful well stimulation technique in an ever-increasing range of environments. Application has spread from the original target 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.

A new fracture diagnostic technology for mapping hydraulic fracture dimensions is introduced: downhole tiltmeter fracture mapping. Downhole tilt fracture mapping involves deploying wireline-conveyed tiltmeter arrays in offset wellbores to measure hydraulic fracture growth versus time. This technology has been employed to map over 100 fracture treatments in the last eighteen months. Allowing, for the first time, the gathering of statistically significant data-sets on how hydraulic fractures actually do grow - albeit, within only a few fields so far. In addition to providing fracture diagnostic data (fracture length, height, width and asymmetry), this new capability allows enhanced utilization of hydraulic fracture models because model predictions can be "calibrated" with insitu observations of fracture growth.

The mapping concept is quite simple: creating a hydraulic fracture involves parting the rock and deforming the reservoir. Downhole tiltmeter mapping involves measuring the fracture-induced deformation in a nearby offset well(s) versus time and depth and inverting the data to obtain the created fracture dimensions. The principles are the same as for surface tiltmeter mapping, but the different array geometry make it very sensitive to fracture dimensions and less sensitive to fracture orientation - just the reverse of surface tiltmeter mapping. This paper will explain the fundamental concepts, the implementation strategy (wireline arrays, processing and modeling), present three field case studies, and briefly discuss the implications on fracture modeling.

This paper introduces a new fracture diagnostic technology that allows economic mapping of hydraulic fracture dimensions. The downhole tiltmeter fracture mapping technology requires the use of an offset wellbore(s) for running wireline-conveyed downhole tiltmeter arrays. For the first time, hydraulic fracture dimensions including growth during pumping can be measured at a relatively modest cost. In addition to providing fracture diagnostic data (fracture height, width and length), this new capability allows enhanced utilization of hydraulic fracture models because model predictions can be "calibrated" with in-situ observations of fracture growth.

The concept is quite simple: creating a hydraulic fracture involves parting the rock and deforming the reservoir. Downhole tiltmeter mapping involves measuring the fracture-induced deformation in a nearby offset well(s) and solving the geophysical inverse problem to obtain the created fracture dimensions. The technology follows the same principles as surface tiltmeter mapping, but the different array geometry and placement make it very sensitive to fracture dimensions and less sensitive to fracture orientation - just the reverse of surface tiltmeter mapping. This paper will explain the fundamental concepts, the implementation strategy (wireline conveyed tiltmeter arrays, data acquisition, processing, and modeling), and three field case studies of measured hydraulic fracture growth.

Recent improvements in tilt measurement techniques have greatly enhanced the resolution of hydraulic fracture-induced tilts, resulting in both greater mapping precision and an increase in the maximum mapping depth achievable with a surface tiltmeter array. With a previous depth limitation of around 6,000 ft., surface tiltmeter mapping was limited to areas with relatively shallow production. Application is greatly broadened now with a depth range down to 10,000 ft. In addition to the expanded depth range, there has been a marked improvement in the fracture mapping resolution.

This paper begins with an overview of the tiltmeter fracture mapping concept, highlighting both the strengths of this technique and its limitations. Following that is a description of the technical advancements made over the last three years to allow fracture mapping at far greater depths. Finally, two brief case studies are presented to demonstrate fracture mapping at great depth, and also to provide insight on hydraulic fracture growth behavior in two different environments. As the case studies make clear, fracture growth is far more complex than is generally assumed. Better understanding of these complexities can lead to significantly enhanced fracture stimulation practices.

The recent and dramatic increase in direct fracture mapping has profoundly altered our understanding of how fractures really do grow. New fracture-mapping technologies have allowed us to often directly measure what we could previously only model or assume. However, perhaps the greatest limitation of these new direct fracture-mapping technologies (tilt and microseismic) is the need for a nearby offset well in which to deploy instruments. In many environments, most notably offshore, there is often no feasible way to employ an offset observation well. Treatment well tilt mapping uses the fracture (injection) well itself as the "observation" well. The goal, quite simply, is to expand the range of environments where direct fracture mapping can be performed.

The concept is simple: if fracture-induced deformation can be measured thousands of feet away at the surface or in offset wells, then it most certainly can be measured in the fracture well itself. The measurement of fracture-induced tilt versus time and depth (via an array of 4 to 20 tiltmeters) can allow robust real-time mapping of fracture height and width. Fracture length is then "modeled" based on observed height and width, and inferred fracture fluid efficiency. Treatment well tilt measurements can also provide direct measurement of mechanical fracture closure aiding, among other things, the estimation of formation closure stress.

This paper presents an analysis of the stress and pressure changes caused by hydraulic fractures and evaluates the likelihood and causes of microseismic activity in the vicinity of the fracture. Coupled with the formation stresses, pressure, and properties, the analysis predicts where microseisms should occur in relation to the fracture and makes possible accurate interpretation of the significance of the microseismic events. The most important factor controlling the seismically active zone is the coupling of the fracturing pressure into the formation. Thus, liquid -saturated reservoirs experience much more widespread activity than gas reservoirs. The analysis also shows that the fracture tip induces large shear stresses that result in a local zone of instability. Such a zone is the primary reason that microseisms accurately map out the length and height of the fracture since considerable microseismic activity occurs around the tip as it propagates.