bluuebunny/crossref_metadata_2025 huggingface dataset:
Unstable Displacement: A Missing Factor in Fracturing Fluid Recovery
Authors: Parmar Jaskaran. S. , Dehghanpour Hassan , Kuru Ergun
Published: October 2012

Multi-stage hydraulic fracturing for stimulating tight reservoirs requires a significant volume of fracturing fluid, which is usually water-base. Water recovery is critical due to environmental considerations, water shortage, and formation damage. This work aims at investigating the role of gravity, fingering, and capillarity on water drainage in propped fractures.

We conduct two sets of drainage experiments. In the first set, we investigate the effect of size, size distribution, and wetting properties of proppants on water recovery. In the second set, we conduct drainage experiments in a physical fracture model. In this model, the proppants are packed in the space between two sheets of glass, and the pack is saturated with the fracturing fluid. This simulates the initial condition before opening the well for flowback. For simulating the water drainage in the fractures above, and below the horizontal well, gas is injected from the top and bottom of the cell, respectively.

For gravity-stable tests where water drains downward, the recovery is controlled by capillary forces, which depend on interfacial tension and proppant size. For gravity-unstable tests where water drains upward, the recovery is poor due to the formation of gas fingers. Increasing the injection pressure does not enhance water recovery in the upward displacement. We conclude that a large fraction of non-recovered fracturing fluid resides in the fractures below the horizontal well.
Flowback Analysis for Fracture Characterization
Authors: Abbasi Majid Ali , Dehghanpour Hassan , Hawkes Robert V.
Published: October 2012

Tight reservoirs stimulated by multistage hydraulic fracturing are commonly characterized by analyzing the hydrocarbon production data. However, analyzing the available hydrocarbon production data mainly determines the fracture-matrix interface. This analysis is not enough for a full characterization of the induced hydraulic fractures. Before putting the well on flowback, the induced fractures are occupied by the compressed fracturing fluid. Therefore, analyzing the produced fracturing fluid should in principle be able to characterize the induced fractures, and complement the production data analysis.

We develop a rate transient model for describing the fracturing fluid flowback. We also make various diagnostic plots for understanding the flowback behavior of three fractured horizontal wells. The diagnostic plots indicate three separate flowback regions. In the first region, water production dominates while in the third region hydrocarbon production dominates. In the second region, water production drops and hydrocarbon production ramps up. In general, we observe a linear relationship between rate normalized pressure (RNP) and material balance time (MBT) for the three regions. However, the proposed model can only describe the response of the first region. We successfully determine the hydraulic fracture permeability by history matching the early time flowback data. We conclude that the flowback analysis can complement the production data analysis for a comprehensive fracture characterization. The presented study encourages the industry to start careful measurement of the rate and pressure data immediately after putting the well on hydraulic fracture flowback.
Simultaneous Estimation of Relative Permeability and Capillary Pressure for Tight Formations from Displacement Experiments
Authors: Zhang Yin , Song Chengyao , Zheng Sixu , Yang Daoyong
Published: October 2012

An ensemble-based technique has been developed and successfully applied to simultaneously estimate the relative permeability and capillary pressure in a tight formation by history matching the conventional measurement data from displacement experiments. Relative permeability and capillary pressure curves are represented by the power-law model. Then, the to-be-estimated coefficients of the power-law model are tuned automatically and finally determined once the measurement data have been assimilated completely and history matched. This new technique has been validated by a synthetic coreflooding experiment and then extended to a real coreflooding experiment. Simultaneous estimation of relative permeability and capillary pressure has been found to improve, while standard deviation of the estimated coefficients is reduced gradually as more measurement data is assimilated. There exists an excellent agreement between both the updated relative permeability and capillary pressure and their corresponding reference values, once all the measurement data are assimilated. The relative permeability can be determined more accurately than the capillary pressure owing to the fact that it is more sensitive to the conventional measurement data. This newly developed technique has good computation efficiency and is suitable for performing uncertainty analysis under the same framework.
Non-Darcy Flow in Shale Nanopores: Do We Have a Final Answer?
Authors: Swami Vivek , Clarkson C. R. , Settari A. (Tony)
Published: October 2012

Many shale gas and ultra-low permeability tight gas reservoirs can have matrix permeability values in the range of tens to hundreds of nanodarcies. The ultra-fine pore structure of these rocks can cause violation of the basic assumptions behind usage of Darcy’s law. Depending on a combination of P-T conditions, pore structure and gas properties, non-Darcy flow mechanisms such as Knudsen diffusion and/or gas slippage effects could be important. Quantifying these effects is critical for correcting laboratory permeability measurements to obtain true (intrinsic) matrix permeability; several authors have also noted that corrections for these effects may also be important when analyzing field data. In order to make corrections for non-Darcy flow, numerous authors have quantified these effects as an apparent permeability that changes as a function of Knudsen number or gas pressure. There are now many correlations available for quantifying apparent permeability changes, but it is not known how much impact they really have on the long term production performance of shale gas wells.

In this work, we summarize the various methods for quantifying non-Darcy flow in unconventional gas reservoirs, and compare the apparent permeability and slippage factor predictions for all the models we have compiled. For determining the impact of the model predictions on well performance, we incorporate the apparent permeability predictions of each model into a numerical simulator, and compare rate-time and cumulative gas-time forecasts for each scenario. The importance of dual porosity (which is usually assumed necessary for shale gas) is also examined. The results of this work are important in several aspects. First, the differences between various formulations of the apparent matrix permeability in shales are illustrated. Secondly, the impact of non-Darcy effects on history matching and recovery forecasting is demonstrated. Finally, it is shown that there may not be a need for dual porosity modeling in certain cases.

The results of this study will be important to professionals involved in laboratory measurement of matrix permeability in unconventional gas reservoirs, modeling well performance, and forecasting shale gas recovery.
Hydraulic Fracture Containment in the Bakken With a Synthetic Polymer Water Based Fracture Fluid
Authors: Hassen Barry , Zotskine Youssouf , Gulewicz Dale
Published: October 2012

Hydraulic fracturing in the Bakken oil reservoir on the Canadian side of the Williston basin involves a risk of connection to the overlying water bearing formations. The Bakken reservoir is a tight dolomitic siltstone which requires multiple stage hydraulic fracturing in horizontal wells to achieve economic oil production rates. Within ten to fifty meters above the Bakken reservoir there often is a higher permeability water bearing interval in the Lodgepole limestone formation. If hydraulic fractures connect to the higher permeability interval in the Lodgepole, then water production and associated handling costs would greatly increase. Any loss of fracture fluid and proppant to the Lodgepole could also reduce effective fracture length within the Bakken and subsequently lead to lower oil production rates. To minimize the potential negative impact of partial hydraulic fracture growth out of zone, several strategies have been used. Some of these strategies include reduction of pump rate, slurry volume and fluid viscosity. Minimizing fluid viscosity without significantly reducing proppant suspension can be a challenge. To address this issue, a unique synthetic polymer water based fluid system with excellent proppant suspension characteristics has been field tested. This system has a viscosity between that of linear gel and typical crosslinked systems and has a unique breaking process. This fluid system has been used in multiple Bakken wells for over one year and field production results will be reviewed to demonstrate the effectiveness of the combined strategies in reducing water/oil ratios. The impact on oil production rates will also be reviewed. The paper will furthermore outline several challenges with deployment in the field. Fracture geometry simulation will be used to demonstrate the expected sensitivity of fracture containment to fracture fluid viscosity and pump rate.
An Investigation of Vertical and Lateral Communication in an Unconventional Oil Reservoir Using Geochemistry and Reservoir Simulation
Authors: Rasdi Faisal , Salman Ahmad , Adams Doyle A. , Sofer Zvi
Published: October 2012

Vertical and horizontal inter-well communication in unconventional reservoirs remains a major uncertainty. This paper presents the results of geochemical analyses performed on several wells in the Bakken and Three Forks unconventional oil reservoirs. Geochemical analyses performed on oil extracted from core, oil sampled while drilling, and oil produced after stimulation indicate that the geochemical signatures of the Bakken and Three Forks Formations are different and unique to its respective stratigraphic units. Using unique geochemical signatures, this study developed a procedure for identifying the production of mixed oils and the relative contribution from each contributing startigraphic units.

To further investigate vertical communication a detailed geologic model was constructed using core and outcrop data. The model was simulated and history matched to estimate contribution from adjacent layers. Various scenarios were simulated to understand the probability of communication. Analyses suggest that vertically adjacent layers contribute to production as predicted by the reservoir model and measured by the geochemical signature of the oil.

This paper demonstrates (a) contribution from vertically adjacent formations can be significant, (b) geochemistry may be utilized to quantify vertical drainage, and (c) quantification of contribution from offset layers helped to constrain a reservoir simulation history match. Results from this study have facilitated the assessment of the degree of vertical communication across various flow units, which is the key to an efficient reservoir development.
Forecasting, Sensitivity and Economic Analysis of Hydrocarbon Production from Shale Plays Using Artificial Intelligence & Data Mining
Authors: Esmaili S. , Kalantari-Dahaghi A. , Mohaghegh S. D.
Published: October 2012

Our understanding of the complexities of the flow mechanism in Shale plays has not kept up with our industry’s interest in these prolific and hydrocarbon rich formations. Furthermore, massive multi-cluster, multi-stage hydraulic fractures, that have proven to be essential for economic recovery from Shale plays, have significantly increased the complexity of the flow behavior and consequently have made the modeling efforts more challenging.

In this paper, the application of a recently developed AI (Artificial Intelligence)-based reservoir modeling approach on Marcellus Shale is presented. In this approach, data mining and pattern recognition techniques were used to initiate modeling of the hydrocarbon production (dray gas and condensate) from Marcellus Shale. Instead of imposing our understanding of flow and transport in shale gas media, which is a very complex and non-linear system, we allow the production history, reservoir characteristics, and hydraulic fracturing data and operational constraint to force their will on our model and determine its behavior.

In this work, the full-field history matching process was performed on a Marcellus shale asset including 135 wells with multiple pads and different landing targets. The full field AI-based Marcellus Shale model then used for forecasting the future well/reservoir performance to assist in planning field development strategies. The goodness of match quality is self-evident, thereby validating this modeling approach. Nevertheless, to examine the model validity in the forecasting mode, the field data was partially matched and then attempted forecasting. Taking validation one-step further, the production performance of a recently drilled well, which was completely blind to the model (was not involved during training and initial validation), was predicted and compared with actual field measurement.

Furthermore, sensitivity and economic analysis are performed in order to identify the impact of different reservoir descriptions (e.g. different reservoir characteristics, stimulation and completion factors) and rank the impact of above-mentioned parameters on the Net Present Value (NPV) of investing on gas wells producing from Marcellus Shale.
Case Studies Suggest Heterogeneity is a Favorable Characteristic of Shale Gas Reservoirs
Authors: Li Jun , Guo Boyun , Ling Kegang
Published: October 2012

Natural gas exploration and production from shale gas formations have gained great momentum throughout the world in the last decade. Producing natural gas from shale is challenging because of the high uncertainty in well productivity. It is imperative to investigate and understand the gas flow mechanism in the shale gas formations. This paper investigates the shale gas production mechanism based on field case studies.

Guo et al.’s analytical well productivity model was employed in this work for analyzing gas productivity of a shale gas well in the Fayetteville Shale basin. Model analyses indicate that shale heterogeneity (natural fractures/custers and organics spots) is a favorable characteristics of shale gas reservoirs because they contribute to the initial and long-term well productivity. Shale gas reservoirs without natural fractures/clusters will not produce natural gas at commercial rates even a few hydraulic fractures are created. The intensity of natural fractures/clusters is a key factor affecting the potential of shale gas wells. Hydraulic fractures are useful for intersecting natural fractures/clusters to make well more productive, but it is not necessary to create high-conductivity fractures for this purpose. Shale gas wells should be placed in the areas where high-natural fracture intensity and solid organic material contents are present.
Utilization of Anisotropic Velocity Models in Surface Microseismic Monitoring to Improve Hydraulic Fracturing Event Location Accuracy in Shale Plays
Authors: Neuhausa Carl W. , Remington Christine , Barker William B. , Blair Keith
Published: October 2012

The work presented in this paper focuses on the application of an anisotropic velocity model in determining microseismic event locations from surface-acquired passive seismic data. The Thomsen parameters ε and δ were determined to accurately locate calibration shots to their known location. Hydraulic fracture events where then imaged and compared to their locations derived from processing incorporating an isotropic velocity model.

Velocity models used in the processing of surface microseismic data are in many cases initially derived from sonic logs and subsequently adjusted based on calibration shots (typically perforations or string shots). A scalar shift is usually applied to the velocity model to locate events at depth. Although calibration shots can be located with sufficient accuracy, this method does not directly account for the anisotropic nature of shales. As determined by Thomsen (1986), anisotropy for nearly vertical wave propagation, is mostly governed by the parameter δ, which is "an awkward combination of elastic parameters" (Thomsen, 1986), and appears to be sensitive to the conformity of the contact regions between clay particles, as well as to the extent of disorder in their orientation (Sayers, 2005). However, the importance of ε increases with with an increasing horizontal component of the propagation path.

Event location accuracy in surface microseismic monitoring is known to be fairly robust using the regularly assumed isotropic velocity model (Thornton, 2011), but this can be further improved in some instances by determining ε and δ to account for velocity anisotropy (Eisner et al., 2011). When compared directly to calibration shot locations derived with an isotropic velocity model, we showed that the absolute average error in calibration shot positioning in all directions was improved by almost 30% and hypocenter events from the hydraulic fracturing treatment depicted a more dense and confined zone of microseismic activity.
Drill Cuttings and Characterization of Tight Gas Reservoirs – An Example from the Nikanassin Fm. in the Deep Basin of Alberta
Authors: Solano N. A. , Clarkson C. R. , Krause F. F. , Lenormand R. , Barclay J. E. , Aguilera R.
Published: October 2012

Estimation of rock properties from drill cuttings is proving valuable in the geologic description of tight gas strata. The characterization scheme includes an integrated analysis of detrital and authigenic mineralogy, pore geometry, and flow and storage capacity using drill cuttings samples calibrated with a limited amount of core data. This methodology has been successfully applied to characterize the fine-grained siliciclastic, shallow marine Nikanassin Formation in the Deep Basin of Alberta.

This workflow is particularly useful for the characterization of undercored low permeability hydrocarbon-bearing intervals from both new and legacy wells. Macroscopic description of drill cuttings samples, coupled with petrographic analysis performed on custom made multi-sample thin sections from the same samples allows a direct correlation between these two observations. The principal detrital and authigenic components are also investigated through microprobe analysis and SEM imaging of selected samples. Porosity values and dominant pore geometries are estimated using laboratory measurements and thin section image analysis. Finally, permeability values are measured using the Liquid Pressure Pulse methodology on drill cutting samples.

Porosity and permeability of the analyzed samples ranges between 2–13%, and 0.01–0.25 mD, respectively. Porosity values from drill cuttings samples are found to be slightly higher than routine core analysis measurements, which in turn usually have higher values than porosity estimated from thin sections. A high degree of reproducibility was confirmed for the porosity values obtained from the saturation method on drill cutting-sized samples, with resultant values comparing very well with measurements from standard nuclear magnetic resonance on the same samples. Reservoir quality within the analyzed samples is highly affected by quartz overgrowth and subsequent carbonate cement, with the former increasing with depth. Compared to the dominant microporosity domain, remnant intergranular porosity significantly enhances the permeability of the samples.

This workflow represents an inexpensive yet comprehensive interpretation tool specially targeted to improve the geological understanding of potential by-passed tight gas formations, which usually lack representative cored intervals. In addition, economic returns can be highly optimized by partial replacement of coring programs by appropriate sampling and preservation of drill cuttings samples in new wells.
A New Foam Rheology Model for Shale-Gas Foam Fracturing Applications
Authors: Edrisi A. R. , Kam S. I.
Published: October 2012

A rapidly-growing energy demand in recent years has made shale gas more attractive than ever. Although shale-gas formations contain a large amount of hydrocarbons, their low-permeability characteristics have been a major impediment to economic development of the fields. Once properly designed, foam fracturing has advantages over the conventional hydraulic fracturing – for example, by using less water, it works better for water-sensitive shale-gas reservoirs; a smaller quantity of water involved makes the fracturing job more environment-friendly due to the reduced amount of chemical additives; and it offers a superior capability to carry and distribute solid proppants over the newly-created factures. In spite of its unique advantages, optimum foam fracturing treatment requires a good understanding of foam rheology.

A series of recent experimental studies revealed that foam flow can be represented by two distinct flow regimes in general: low-quality regime showing stable plug-flow pattern, and high-quality regime showing unstable slug-flow pattern. This study, for the first time, presents how to develop a comprehensive foam model that can handle a variety of bubble-size distributions and flow patterns by using two-flow-regime concept for fracturing.

Analyzing experimental data of surfactant foams and polymer-added foams shows that (i) in the low-quality regime, foam rheology is governed by bubble slippage at the wall with no significant change in its fine foam texture and (ii) in the high-quality regime, foam rheology is governed by the relative size of free-gas segment to fine-textured foam-slug segment. By using these governing mechanisms, this new foam model successfully reproduces foam flow characteristics as observed in the experiments, including almost horizontal pressure contours in the low-quality regime and inclined pressure contours in the high-quality regimes. Although the model is built with a power-law fluid model, the same procedure can be taken for Bingham-plastic or yield-power-law fluids.
Using Production Data to Generate P10, P50, and P90 Type-Curves for Shale Gas Prospect
Authors: Williams-Kovacs J. D. , Clarkson C. R.
Published: October 2012

As a result of improved technology and declining conventional gas reserves, shale gas (SG) and other tight-rock reservoirs have emerged as significant sources of oil and natural gas.

Since late-2008 natural gas prices have been depressed in North America as a result of oversupply with unmatched demand. Suppressed commodity pricing has made unconventional gas production uneconomic or marginally economic in many areas, which places a greater emphasis on prospect analysis and careful selection of areas of investigation and drilling locations.

This paper discusses a new tool that was developed specifically for generating probabilistic (P10, P50 and P90)1 type curves for shale plays, based on a series of input production wells, which can be used in the early stages of the stochastic analysis of shale gas prospects. This technique will be discussed in detail and a sample case will be given to demonstrate the methodology for a simulated prospect. This methodology combines the use of a cumulative probability distribution (cumulative distribution function – CDF) for a key distribution parameter (i.e. one year cumulative gas produced) with flowing material balance (FMB) to estimate original gas-in-place (OGIP) and drainage area and the square root of time plot analysis to estimate linear flow potential (kmAcm). The results of these analysis techniques are then combined with estimates of other key PVT and reservoir parameters to generate a type curve for each of the probability levels of interest. These type curves can then be used in the stochastic analysis of SG plays using a methodology such as that presented by Williams-Kovacs and Clarkson (2011) for unconventional prospect screening.
Experimental Study of Polymer-free and Polymer-added Foams for Underbalanced Drilling: Are Two Foam-Flow Regimes Still There?
Authors: Edrisi A. R. , Gajbhiye R. N. , Kam S. I.
Published: October 2012

Foam-assisted underbalanced drilling technique is advantageous over the traditional overbalanced drilling near the productive water-sensitive formations due to its reduced formation damage, improved rate of penetration, higher cutting-transport capacity, and lower circulation losses. However, the complicated nature of foam rheology has been a major impediment to the optimal design of field applications.

Earlier studies with surfactant foams without oils and polymers show that foam flow in pipe can be represented by two different flow regimes: the low-quality regime showing either plug-flow or segregated-flow pattern, and the high-quality regime showing slug-flow pattern. The objective of this study is to investigate foam flow characteristics in horizontal pipes at different injection conditions, with or without oils, by using polymer-free and polymer-added surfactant foams.

The results of this study were presented in two different ways: (i) steady-state pressure drops (or, apparent foam viscosity, equivalently) measured by multiple pressure taps and (ii) visualization of bubble size, size distribution and flow patterns in transparent pipes. The results with surfactant foams and oil showed that (i) oil reduced the stability of foams in pipes, hence, decreasing the steady-state pressure drops and foam viscosities, and (ii) the presence of oil tended to lower the transition between the high-quality and the low-quality regimes (i.e., lower foam quality at the boundary, or lower fg* equivalently). In addition, the results with surfactant foams with polymer showed that (i) polymer thickened the liquid phase and, if enough agitation was supplied, could make foams long-lived and improve foam viscosities, and (ii) the system sometimes did not reach the steady state readily, showing systematic oscillations. In both cases, though, the experiments carried out in this study showed the presence of two distinct high-quality and low-quality flow regimes.
Link between Rocks, Hydraulic Fracturing, Economics, Environment, and the Global Gas Portfolio
Authors: Aguilera Roberto F. , Ripple Ronald D.
Published: October 2012

This paper presents a methodology for connecting geology, hydraulic fracturing, economics, environment and the global natural gas endowment in conventional, tight, shale and coalbed methane (CBM) reservoirs. The volumetric estimates are generated by a variable shape distribution model (VSD). The VSD has been shown in the past to be useful for the evaluation of conventional and tight gas reservoirs. However, this is the first paper in which the method is used to also include shale gas and CBM formations.. Results indicate a total gas endowment of 70000 tcf, split between 15000 tcf in conventional reservoirs, 15000 tcf in tight gas, 30000 tcf in shale gas and 10000 tcf in CBM reservoirs. Thus, natural gas formations have potential to provide a significant contribution to global energy demand estimated at approximately 790 quads by 2035.

A common thread between unconventional formations is that nearly all of them must be hydraulically fractured to attain commercial production. A significant volume of data indicates that the probabilities of hydraulic fracturing (fracking) fluids and/or methane contaminating ground water through the hydraulically-created fractures are very low. Since fracking has also raised questions about the economic viability of producing unconventional gas in some parts of the world, supply cost curves are estimated in this paper for the global gas portfolio. The curves show that, in some cases, the costs of producing gas from unconventional reservoirs are comparable to those of conventional gas.

The conclusion is that there is enough natural gas to supply the energy market for nearly 400 years at current rates of consumption and 110 years with a growth rate in production of 2% per year. With appropriate regulation, this may be done safely, commercially, and in a manner that is more benign to the environment as compared with other fossil fuels.
Well Construction Optimization in the Montney Formation in the Karr Kakwa Area of Central Western Alberta: A Case Study
Authors: Teichrob Bob , Hucik Barry , Shirkavand Farid , Schmitz Ron , Haysom Steve , Nevokshonoff Glen
Published: October 2012

Seven Generations Energy Ltd. (7Gen) has drilled several horizontal wells in the extremely liquids rich Montney formation in the Karr Kakwa area of central western Alberta. Over the last two years we have seen progressively shorter drilling times as well as a marked increase in production as a function of optimal hydraulic fracturing recipes and completion installations. This paper will discuss the systematic approach taken by well construction engineers to optimize drilling performance through bit selection coupled with vibration mitigation and hydraulics optimization. Further technologies that will be discussed and will/have been be implemented are torque mitigation technologies to mitigate stick slip and the use of managed pressure drilling techniques to decrease mud density and further increase ROP’s. This paper will also discuss the coincident work done to optimize fracture treatments as a function of rock strength and measured gas response while drilling.
Nanostructure vs. Macroscopic Properties of Mancos Shale
Authors: Torsaeter M. , Vullum P. E. , Nes O.-M. , Rinna J.
Published: October 2012

Shale gas reservoirs have become financially attractive upon more efficient utilization of technologies such as horizontal drilling and hydraulic fracturing. In order to better identify such reservoirs, estimate their production potential, as well as device optimum drilling and fracturing strategies, a detailed understanding of the connection between gas shale macroscopic mechanical and petrophyscal properties and microstructure is highly valuable. Since a high fraction of both pores and grain structures in gas shales are of nanometer sizes, this requires advanced experimental techniques beyond what has commonly been applied on more conventional coarsely grained reservoir rocks. We present a study of the Mancos outcrop shale where we combine results from state-of-the-art nano tomography with results from standard rock mechanical, petrophysical, and geochemical testing. In addition to providing the first detailed investigation of the Mancos shale on the nanometer pore scale, this multi-scale analysis contributes to bridging the gap between small- and large-scale gas shale descriptions – and to establish the role of nano tomography in relation to more standard rock testing procedures. Our study revealed that the Mancos shale is marginally mature (%Ro ~ 0.66–0.70), gas prone and has a total organic content of 1.0–1.3 wt%. It is observed that even if the porosity of the organic matter itself is very low, organics are found in or around all analyzed fractures and voids in the Mancos sample. Large fractures parallel to bedding are observed to be organic-rich, potentially enabling the soft organic material to serve as a preferential weak plane when the rock is subjected to mechanical stress. This may be reflected in the observed significant strength anisotropy of about 60% deduced from rock mechanical tests on the same material. It is also suggested that nano/microfractures influence the measured acoustic properties, which appear consistent with those of other organic rich shales. Thus, knowledge of the detailed nanostructure, especially the distribution of organic matter, its porosity and its interface towards other solid phases, may be beneficial when attempting to predict shale macroscopic mechanical and petrophysical properties. Knowing these simplifies the process of identification and characterization of shale gas prospects, as well as the subsequent drilling and production.
Dynamic Cementation Improves Wellbore Construction and Reduces the Hazards of Groundwater Contamination in Shale Plays
Authors: Holt C. , Lahoti N.
Published: October 2012

The well construction process only allows one chance to install a primary cementing system. The industry has long understood the advantages of the method of pipe movement during cementing operations, yet it is not commonly practiced in spite of API recommendations. One barrier to implementing this methodology has been the availability of tools and technology. Application of a modern casing running tool (CRT), with a top drive allows the casing string to be safely conveyed to bottom, and subsequently rotated and reciprocated during cementing.

The standard industry toolbox uses long bails attached to the traveling block, conventional casing elevators and a standard cement head. Practically, this does not allow for rotation during cementation. Rigging up this equipment is time consuming and leaves the pipe motionless on bottom. Cement jobs under these circumstances are more prone to failure and frequently require remedial cementing.

Most North American operators are drilling extended reach wells in the prolific onshore shale plays. Long laterals combined with tortuous wellbores make it difficult to conventionally run casing; as a result, usually these sections require casing rotation to pass through challenging trajectories and get to bottom. Moreover, the horizontal shale wells are often completed with multi-stage frac jobs. It is imperative to have high quality cement job to insure zonal isolation, otherwise communication between zones can occur; this can result in a lower quality frac job and well completion. A poor completion can result in lost production and leaks can lead to ground water contamination. After pumping stops, there is no known method to affect additional mud removal from continued pipe movement, but cement job quality is not dependent solely on mud removal.

The drilled section is of little value until it is cased and a competent cement job is completed. Dynamic Cementation™ consists of rotating and reciprocating the casing from the time the cement operation commences until cement is set. It can increase the quality of the cement job by increasing mud removal and decreasing pressure loss while cement cures. This paper discusses the benefits of casing movement during cementing, the methodology and results.
Rate Transient Analysis of Stress-Sensitive Formations during Transient Linear Flow Period
Authors: Qanbari F. , Clarkson C. R.
Published: October 2012

Rate- and pressure-transient analysis of unconventional gas and oil reservoirs is a challenge because of complex reservoir characteristics that dictate flow. An important flow regime for analysis of these reservoirs is transient linear flow, which can be associated with linear flow to induced hydraulic fractures or to horizontal wells. One of the complications in the analysis of this flow regime is stress-sensitivity of porosity and permeability. This work aims to provide a method for analyzing transient linear flow in reservoirs with stress-sensitive permeability.

Flow of a compressible fluid in a stress-sensitive formation is governed by a nonlinear second order partial differential equation (PDE) with nonlinearities in both the accumulation and flow differential terms. A version of the Kirchhoff transformation is used to make the accumulation term linear, while a monotonically varying nonlinearity (as a function of a new pseudopressure function introduced in this work) exists in the flow differential term. The transformation, however, does not introduce any nonlinearity to the constant-wellbore pressure-condition, which is the case for constant well flow rate.

An exact solution of the transformed nonlinear PDE is provided for pressure distribution and flow rate calculations. The results are compared with approximate solutions in which fluid and rock properties are considered to be constant and evaluated at a specified pressure, as obtained by the error function (erf) solution. The results show that, at the wellbore, the value of the slope of the square-root of time plot (reciprocal of flow rate vs. square-root of time) can be used to calculate one of the two parameters, permeability modulus or initial permeability. This is the case if the derivative of the Kirshhoff parameter with respect to the Boltzmann variable is known for different values of fluid and rock compressibility, permeability modulus, and pressure drawdown. In this study, the Fujita’s method is used to calculate the derivative for some ranges of the affecting parameters. The results are presented as plots which can be used for analyzing the production data.
Well Production Performance Analysis for Unconventional Shale Gas Reservoirs: A Conventional Approach
Authors: Hategan Florin , Hawkes Robert V.
Published: October 2012

Over the last several years, horizontal drilling and multi-stage hydraulic fracturing have become the norm across the industry and proved crucial for economic production of natural gas from unconventional shale gas and ultra tight sandstone reservoirs, also referred to as nano-Darcy reservoirs.

Following the success of the Barnett shale, horizontal drilling and multi-stage hydraulic fracturing has spread across North America with new emerging shale gas plays such as the Eagle Ford, Woodford, Haynesville, Marcellus, Utica, Horn River changing the industry’s landscaping. In the current economic environment of high drilling and completion costs, coupled with lower commodity prices, the economic success of shale gas developments has become reservoir specific.

Evaluation of well’s initial performance in a particular field and especially the ability to accurately predict the long term production behavior and EUR is critical to the efficient deployment of large capital investments. Field analogies making use of arbitrary "type curves" can have a significant negative impact on the project’s bottom line.

With the growing number of multi-stage horizontal wells producing from shale gas reservoirs, many "unconventional" production analysis techniques have been developed based on new concepts such as stimulated reservoir volume (SRV), fracture contact area (FCA), or sophisticated mathematical relationships (power law decline curves, linear flow type curves, to name a few). These sophisticated engineering processes are well documented in the literature and have been presented at numerous industry work shops and conferences. However, for the majority of these techniques there is one common reoccurring theme: performance evaluation of shale gas production cannot be analyzed using conventional methods (e.g. Darcy’s Law).

This paper will demonstrate how the conventional approach of reservoir characterization, well performance evaluation and forecasting, can be implemented for all unconventional gas reservoirs, using traditional well testing and production data analysis techniques. We will present one simple analytical model based on the solution of the pseudo steady state equation and will introduce the concept of a shale gas normalized production plot. In our view, the shale gas normalized production plot is one type curve generally applicable to any shale gas reservoir.

Finally, pre-frac in-situ testing techniques will be reviewed and special consideration will be given to the perforation inflow diagnostic (PID) testing. We will emphasize the importance of specific reservoir parameters (pore pressure and in-situ shale matrix permeability) and show their impact on drilling and completion strategy and design. Field case examples including well test results and production data from wells completed in several shale gas reservoirs are presented.
Parametric Sensitivity Study of Chemo-Poro-Elastic Wellbore Stability Considering Transversely Isotropic Effects in Shale Formations
Authors: Huang Lu , Yu Mengjiao , Miska Stefan , Takach Nicholas , Bloys J. B.
Published: October 2012

A chemo-poro-elastic wellbore stability model considering the shale transverse isotropic effect is developed. In poroelastic theory, the pore fluid motion and solid structure deformation are coupled. Lubinski’s one-way coupling scheme is adopted in this study which assumed a rock has strong structure and the effect of solid skeleton deformation on fluid flow is negligible.

It is found that normal stress along the cylindrical axis is affected by Young’s modulus on both the symmetrical plane and the axial direction.

A Taguchi orthogonal simulation design strategy is adopted to reduce the number of simulations while still achieving meaningful results. Analysis of variance (ANOVA) is conducted and parameter contributions to the mud weight window have been investigated. It can be found that among the 11 parameters of interest, wellbore inclination angle, hydraulic conductivity and water activity of drilling fluid play the most important roles in determining the mud weight window.

Knowledge of percentage contributions of the parameters in this chemo-poro-elastic wellbore stability model greatly helps drilling engineers identify the critical factors for wellbore stability control. This study also helps well trajectory design and drilling fluid optimization.
The Use of Electromagnetic Mixing Rules for Petrophysical Evaluation of Dual and Triple Porosity Reservoirs
Authors: Olusola Bukola K. , Guang Yu , Aguilera Roberto
Published: October 2012

Electromagnetic mixing rules of the type developed by Maxwell Garnett, Bruggeman, and the Coherent Potential formula are shown to be useful for evaluation of the porosity (or cementation) exponent, m, in naturally fractured reservoirs represented by dual and triple porosity models. Comparisons are made with core data from limestone, dolomite and tight gas reservoirs to corroborate results from the theoretical models.

Rigorous values of m reduce the uncertainty in calculated values of water saturation and hence improve estimates of hydrocarbons-in-place and recoveries particularly in situations where sufficient data are not available to utilize the material balance approach.

The main advantage of the new method developed in this paper for petrophysical analysis is that it can handle with the use of one single equation the individual mixing rules mentioned above, and at the same time quantify values of matrix, fracture and non- connected vug porosity, and the cementation exponent of the total porosity system.

It is concluded that electromagnetic mixing rules provide a useful methodology for petrophysical evaluation of complex dual and triple porosity reservoirs.
Updip Water Blockage in the Nikanassin Basin Centered Gas Accumulation, Western Canada Sedimentary Basin
Authors: Ramirez John F. , Aguilera Roberto
Published: October 2012

A basin centered gas accumulation (BCGA) is a "continuous petroleum accumulation" characterized by low permeability, the absence of downdip water, the absence of obvious traps and seals, the presence of pervasive gas or oil saturation over very large areas, abnormal pressures (either high or low), and the relative proximity to source rocks. The question is if it is reasonable to think that gas can be trapped over millions of years by an updip water block.

A reservoir simulation model has been created in order to answer this question. The water seal is shown to be the result of very low permeability and high capillary pressures, properties that are generally found in tight gas formations. The model is defined by a geometry that mimics the geologic interpretation of the Nikanassin BCGA in the Western Canada Sedimentary Basin (WCSB) and rock properties that provide a good representation of the real behavior of the reservoir in the Deep Basin. Different models were created trying to understand sensitivities to permeability and capillary pressure in the distribution of downdip gas and updip water over thousands of years. The results obtained appear consistent and reliable when compared with factual information from the Deep Basin.

The conclusion is reached that updip water blocks provide good seals in the Deep Basin. The simulation also confirms that special completion and stimulation practices are required in order to produce gas at economic rates from tight gas reservoirs.
Appraisal Excellence in Unconventional Reservoirs
Authors: Burkholder M. K. , Coopersmith E. M. , Schulze J. H.
Published: October 2012

Unconventional resource plays are breaking the rules of conventional decision wisdom. Rules of thumb developed over years of producing conventional assets are no longer always applicable and teams are struggling to uncover the new protocols. In unconventional, the demarcation line between appraisal and development is blurred as teams attempt to simultaneously hold acreage, explore, appraise and develop, ever striving to increase the pace to commercial sanction.

This paper presents a pragmatic approach to frame, evaluate and compare appraisal strategies in resource plays. The unique approach starts with framing the overall field appraisal plan, holistically, and then progresses to evaluating the most commonly encountered individual appraisal decisions, enabling teams to answer the following questions:

What are our key uncertainties and which appraisal options should we consider to resolve them? Is there value in running a pilot to determine the optimal well spacing and, if so, what is the best pilot design? Do we want to run a completions pilot and how should we configure it? Do we need to pilot where to and how to orient our laterals? Can we justify seismic to high grade our drilling program?

Appraisal framing is particularly valuable when taking on big acreage projects, helping teams identify new alternatives, organize options and look for interesting and innovative combinations. It also serves as a great tool to help teams work together. From surface to drilling, the process is inclusive, which is an important aspect in unconventional resources where cross discipline integration is so important.

The appraisal part of resource plays is as much or more about finding the exit points for different parts of the play as it is about learning and optimizing the commercial developments. Sometimes there may be no benefit of the new information from a Net Present Value (NPV) perspective and yet there is benefit to understanding the uncertainty reduction potential of different programs and knowing when projects are on the right path. This methodology is different than simply projecting learning curves on a development strategy and going forward. With this approach, teams clearly understand their walk points and rationale for them—helping compare different spending programs in order to understand and optimize recommended plans.

This paper provides an example of appraisal excellence in unconventional resource plays through an example which demonstrates some of the practical tips, tricks and tools which have proven to be effective for teams wrestling with these types of issues.