Complex Toe-to-Heel Flooding (CTTHF) is a short distance flooding technique developed by the authors for sandstone formations. CTTHF applied on horizontal wells and requires at least one barrier and injector hydraulic fracture, also it requires at least one method to control early water production. This paper discusses the design aspects of the CTTHF including the design of barrier fracture, injector fracture, and the produced water control methods. Technical and economical evaluation to rank different design setups is performed and presented.
Advanced commercial reservoir simulator with hydraulic fracturing module was used to simulate different CTTHF setups and reservoir conditions to set the reservoir selection criteria and proper design methodology. In this study, Toe-to-Heel Waterflooding was considered the base case. Sensitivity studies for barrier fracture and injector design has been achieved and presented. Moreover, a sensitivity studies for hydraulic fractures spacing, number of barrier fractures, batch injection scheduling and changing packer location have been performed.
When CTTHF is applied in high permeable sandstone formation, early water production is expected, except produced water control method is used. This study states the feasibility conditions for each proposed produced water control technique. Also, a methodology for candidate reservoir selection, design of barrier and injector fractures is developed and presented. There are multiple fluid systems can be used to create the barrier to seal a pre-determined zone. CTTHF is better reservoir management approach.
The novelty of the CTTHF is giving multiple options for produced water control that maximizes the produced oil and minimizes the water production. CTTHF's produced water control can make some reservoirs economic to produce.
Operators continue their quest to better understand and design completion strategies to maximize reservoir contact and optimize well spacing. This paper presents a case study that analyzes completion design effectiveness, using pressure data acquired from isolated monitor stages on offset wells during treatment of adjacent wells. The method was employed on three wells of a seven-well pad in the Marcellus, to assess fracture growth and evaluate the performance of employing intra-stage and inter-stage diversion.
Poromechanically-induced pressure responses on isolated monitor stages on offset wells during treatment of an adjacent well, are compared to a fully coupled, three-dimensional, finite element effective stress model, to calculate dominant fracture geometries that correspond to the pressure response induced in the rock. The initiation points and ascending magnitudes of the responses approaching the isolated monitor stage qualify the performance of inter-stage diversion, whereas the fracture growth trends and geometries speak for the efficacy of the intra-stage diversion and overall stage design.
The first well utilized inter-stage diversion and dissolvable plugs to isolate stages; the second well utilized intra-stage diversion to improve cluster efficiency with regular frac plugs for zonal isolation; and, the third well employed regular frac plugs with no use of diversion. This presented a unique opportunity to compare and analyze the fracture growth rates, trends, and geometries, while applying inter-stage diversion and frac plug completion designs for zonal isolation on the same pad.
This paper is a comparative study to understand the value of using inter-stage diversion, along with dissolvable plugs in place of composite frac plugs, after every stage to attain zonal isolation. In addition, completed stages utilized different fluid designs, providing the opportunity to analyze the impact of fluid design on fracture growth trends and diverter performance. The results are interpreted using pressure data-derived fracture maps with production data, which point to the performance of various completion strategies, using an entirely new diagnostic method.
This paper presents a method for pinpointing intervals for fracture stimulation in horizontal wells targeting unconventional oil plays. The observation of crossflow among fractures has been of great concern as this phenomenon affects the productivity of producing wells. The cause is related to the effectiveness of fracturing stages, which by itself depends on the rock lithology. We identified interaction among fractured intervals from diagnostic modeling of performance data that exhibited cross flows in the wellbore. On wells exhibiting the most prolonged duration of crossflow, we noted the disadvantages of equal space fracturing. We then used the drilling parameters from MWD data for individual wells and computed the d-exponent profiles and noted significant differences in rock brittleness as characterized by their d-exponent data. Out of the more than 60 wells studied, wells exhibiting minor changes in the d-exponent showed the least indications of cross flows from performance data while in wells with significant cross flows we see the nonuniformity of the d-exponent profile and the negative impact of equal space fracturing.
In the past ten years, hydraulic fracturing technology and strategies have made major improvements in the operational efficiency and economic performance of shale well completions. Much of this advancement was derived in the past three years as a response to the global downturn in oil and gas commodity pricing. Mature shale plays across the United States have a surplus inventory of horizontal wells employing highly inefficient completions styles. Amid the low oil pricing environment, operators in the Bakken and Eagle Ford were capable of revitalizing these prior generation wells with great success through re-fracturing programs. In many cases, production of these re-fractured wells rivaled the production of newly drilled and completed shale wells both in terms of initial production post re-fracture as well as extended interval cumulative production. These re-fracturing programs allowed producers to achieve tremendous gains in production while minimizing drilling activity. Although re-fracturing began as a highly economical method to improve production during a time of depressed oil pricing, it is still being used today to improve the production of additional wells recognized as top-tier candidates.
By developing a specific set of criteria to select wells for re-fracturing, these programs can be successfully employed in the Appalachian Basin to improve the economics of gas wells, mitigating the effects of highly discounted natural gas pricing. After the explanation of well candidacy, an economic sensitivity analysis was implemented to illustrate the impacts a strong re-fracturing program could make for operators in the Northeast through a comparison of public data showing production and total reserves for both in and out-of-basin re-fracturing programs. Additionally, while this paper focuses on re-fracturing as it relates to shale formations it also includes information as to how re-fracturing relates to conventional formations.
After looking at the incremental economics of re-fracturing programs implemented in shale plays across the United States and in-basin data, the impacts of gas well re-completion can be fully quantified and understood through the application of probabilistic modeling. Additionally, this modeling further delineates re-completion candidacy by identifying which wells pose higher risks in economic metrics.
Very little information has been published regarding the impacts a re-fracturing program could have in the Appalachian Basin. As the field matures, the topic of re-completions will become increasingly important, and this analysis will allow operators to have a greater understanding of the impacts of refracturing shale gas wells in the Northeast.
Low injected fracturing fluid recovery has been an issue during flowback period that is highly impacted by the fracture closure behavior. Although existing flowback models consider fracture closure volumetrically, they do not represent the true situation of non-uniform fracture closure. In this paper, we proposed a coupled geomechanics and fluid flow model for early-time flowback in shale oil reservoirs. The fluid flow model is coupled with an elastic fracture closure model through finite element methods. In this study, three stages are modeled: fracture propagation, well shut-in and flowback. Cohesive Zone Method (CZM) has been used for modeling fracture propagation. The presented model distinguished the propped part from the unpropped part of the fracture. At the beginning of flowback, the proppants may not be completely compacted in early shut-in time. Thus, permeability evolution during closure is tracked using a smooth permeability transition function. The numerical results have shown that fracture closure during the flowback period is often not uniform. While the uniform fracture closure leads to maximum fracturing fluid recovery, an aggressive pressure drawdown strategy may damage fracture connectivity to the wellbore. An integrated flowback model enables modelling nonuniform fracture closure in a complex fracture network. This study highlights that by choke/pressure drawdown management, operators can influence fluid recovery and even maintain high fracture conductivity. Furthermore, the methodology presented in the paper can also be used for inverse analysis on early flowback data.
Production data and analytical models derived from coupling the linear flow in the reservoir and the linear flow in hydraulic fractures were used in this study to optimize fracture spacing for maximizing productivity of shale oil and gas wells through refracturing. This study concludes that productivity of multi-fractured horizontal wells is inversely proportional to the fracture spacing. The shortest possible fracture spacing should be used to maximize well productivity through refracturing. This supports the practice of massive volume fracturing where as many as perforation clusters with the shortest possible spacing are used for pumping massive proppant into the created hydraulic fractures. Production data analysis indicates that the multi-fractured horizontal oil and gas wells could have higher productivity if they were fractured with less perforation cluster spacing. Mathematical model analysis implies that reducing the cluster spacing from 70 f t t o 15 f t t h r o u g h r e f r a c t u r i n g c a n d o u b l e d w e l l p r o d u c t i v i t y, w i t h t h e M i n i m u m Re q u i r e d C l u s t e r S p a c i n g (MRCS) determined by well completion constraints (packers, perforation clusters, and casing couplings). Result can be checked for fracture trend interference on the basis of analyses of pressure transient data or production data.
The Marcellus formation has begun to attract more attention from the oil and gas industry. Despite being the largest shale formation and biggest source of natural gas in the United States, it has been the subject of little research. To fill this gap, this study experimentally examined the rock properties of twenty core samples from the formation.
Five tests were performed on the core samples: X-ray computerized tomography (CT) scan, porosity, permeability, ultrasonic velocity, and X-ray diffraction (XRD). CT-scans were performed to identify the presence of any existing fracture(s). Additionally, helium was injected into the core samples at four different pressures (100 psi, 200 psi, 300 psi, and 400 psi) to determine the optimal pressure for porosity measurements. Complex Transient Method was employed to measure the permeabilities of the core samples. Ultrasonic velocity tests were conducted to calculate the dynamic Young's moduli (E) and the Poisson's ratios (ν) of the core samples at various confining pressures (in increments of 750 psi between 750 psi and 4,240 psi). Finally, the mineralogical compositions of the core samples were determined using the XRD test.
The results of the CT-scan experiments revealed that seven core samples contained fractures. The porosity tests yielded an optimal pressure of 200 psi for porosity measurement. The measured porosities of the samples were between 6.43% and 13.85%. The permeabilities of the samples were between 5 nD and 153 nD. The results of the ultrasonic velocity tests revealed that at the confining pressure of 750 psi, the compressional velocity (Vp) ranged from 18,411 ft/s to 19,128 ft/s and the average shear velocities (Vs1 and Vs2) ranged from 10,413 ft/s to 11,034 ft/s. At the same confining pressure, the Young's modulus and Poisson's ratio ranged from 9.8 to 10.8 million psi and 0.25 to 0.28, respectively. Increase in the confining pressure resulted in increases in the Vp, Vs, Young's moduli, and Poisson's ratios of the samples. The results of the XRD test revealed that the samples were composed of calcite, quartz, and dolomite.
This study is one of the first to characterize core samples obtained from the formation outcrop by performing five tests: CT-scan, porosity, permeability, ultrasonic velocity, and XRD. The results provide detailed insights to researchers working on the formation rock properties.
In shale formations, operators are constantly seeking new technologies to improve proppant transport and conductivity in order to boost production. A novel technique known as surface modified proppant (SMP) has been pumped in more than a dozen wells in the United States, with proven results of increased production. This paper demonstrates and analyzes a case study for a Marcellus shale development where two wells are presented. Well A applied the SMP technique while the offset, Well B, was stimulated without the technology. After three years, Well A yielded an 18% increase in normalized cumulative gas production over the offset Well B.
In presenting the benefits of this technique, the paper provides a brief overview of the development of the conductivity enhancer; the case study; 3D reservoir and hydraulic fracturing simulator selection; model setup and simulation results. SMP is a chemical additive that, when pumped, creates a buoyancy effect of proppant particles upon entering the fracture network. This dynamic SMP application also propels proppant transportation, prevents proppant settling and enhances the fracture network conductivity by increasing the volume by which sand inhabits the fracture network. Increasing the proppant pack height enables deeper penetration into the fracture network, allowing for an increase in proppant distribution and ultimately enhancing the stimulated rock volume (SRV). We have been able to prove the application in both the lab and field scale tests. The impact of the SMP proppant is investigated by performing numerical simulations of hydraulic fracturing and subsequent production.
Along with clear results showing better proppant placement using the simulator with the conducted study, we further explain the completion effectiveness. We outline advantages and the ease of pumping the SMP, including design optimization, thus making this technology cost beneficial.
Hydraulic fracturing is a typical and vital technique applied in shale gas reservoir development. Numerical simulation used to be a common tool to optimize the parameters in hydraulic fracturing design determining the stage numbers, injection pressure, proppant amount, etc. However, the current understanding of shale gas storage and transport mechanism (e.g. adsorption/desorption, diffusion) is basically adopted from the lessons learned from coal seams through past experience, which might not help an efficient numerical simulation development.
In this study, how artificial intelligence assisted data driven models assist the hydraulic fracturing design in shale gas reservoir is discussed. It starts by collecting field data and generate a spatial-temporal database including reservoir characteristics, operational/production information, completion/stimulation data and other variables, Neural Network models are then developed to study the impacts of all parameters on gas production as well as perform history matching of the field history. The AI assisted model with acceptable matching of field data can be used to model different hydraulic fracturing design scenarios and provide predictions on well production.
Production from shales can be dependent on many things, including multiple reservoir properties, drilling, completion and production methods. Designs and analyses often focus on drilling and completion issues, such as number of stages, wellbore length and fracture properties, such as conductivity, length, spacing and complexity. As a result, many aspects of the reservoir, fractures and production methods can be significant. Flow from the reservoir to production points is driven by pressure drops. If an entire well including fractures and surrounding reservoir is considered as a single system, then the production behavior is driven by the magnitude of three pressure drops and corresponding resistances to flow in the system. Those that need to be considered are: pressure drop between the reservoir and the fractures, pressure drop along the fractures to the wellbore perforations and pressure drop along the wellbore to the pump inlet or tubing head. Different aspects of the well/fracture/reservoir system become important, or unimportant, depending on the relative magnitude of these pressure drops and resistances to flow. For example, many people believe that fractures should be as long as possible assuming they can be restricted to zones of interest and do not interfere with other wells and/or fractures. However, since the pressure along a fracture increases as you move further away from the wellbore, increasing fracture length can have diminishing returns for reservoirs with small reservoir to fracture pressure drops and/or low fracture conductivities.