Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO2 injection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N2 injection were also recorded for comparison.
Low to ultra-low permeability tight oil reservoirs have recently become a significant source of hydrocarbon supply in North America, Production and pressure transient analysis of tight oil reservoirs is one of the most difficult problems facing a reservoir researcher because of the extreme complexity inherent in tight formations, To produce oil and gas commercially from tight formations, naturally completed (open-holed) or cased horizontal wells with multi-stage hydraulic fractures are the most popular implementation for completion, and such kind of application is expected to create a complex sequence of flow regimes (
This paper provides a detailed discussion of numerical method of pressure transient and rate responses for hydraulically fractured horizontal wells in tight formation and compared with analytical (semi-analytical) methods based on the Bakken and Viking Formation in Western Saskatchewan. For Numerical simulated pressure transient responses, a naturally-completed (open-hole) and cased horizontal well with multiple transverse hydraulic fractures in a homogeneous or a sizable natural fracture system are considered. Numerical method for pressure and rate transient analysis is generated by employing a commercial reservoir simulator, CMG IMEX, a 3D finite-difference reservoir simulation package which is widely and popularly accepted by petroleum industry. As noted by many findings, it is shown that fully-filled and regional natural fractures would display various pressure transient characteristics and, hence, considerably affects well production performance. In addition, these conductive, interconnected natural fractures dominate the pressure transient performances of horizontal wells in tight formations even with the presence of hydraulic fractures. Additionally, the simulation runs also indicate that if the reservoir is naturally fractured to some extent, hydraulic fracturing stimulation might not improve productivity significantly, unless a large amount of hydraulic fractures and infinite conductivities can be achieved. To demonstrate the feasibility of numerical simulation models, there is a representative contrast between numerical and analytical (semi-analytical) methods. To demonstrate the feasibility of numerical simulation models, there is a representative contrast between numerical and analytical (semi-analytical) methods.
Schilling, John (Marathon Oil Company) | Cooley, Emy (Marathon Oil Company) | Azar, Mike (Schlumberger) | White, Allen (Schlumberger) | Koffler, Kerry (Schlumberger) | McDonough, Scott (Schlumberger) | Self, Jordan (Schlumberger) | Krough, Bradley (Schlumberger)
The Three Forks First Bench (TF1) in the Williston Basin is attractive to operators for its production qualities; however, the formation is problematic for drilling with polycrystalline diamond compact (PDC) bits. TF1 is an interbedded dolostone, 30 to 40 ft thick, capped by the abrasive Pronghorn/Sanish formation with high stress variations/spikes and laminations. These formation characteristics lead to cutter damage and vibration, which cause slow rates of penetration (ROP) and additional trips due to bit/bottomhole assembly (BHA) failure.
In response to these challenges, a revolutionary rock-removal system has been designed. The system implements conical diamond elements (CDE) to work in unison with the PDC cutters. Conventional PDC bits complete a typical 10,000-ft TF1 lateral in a one-bit/BHA in only one out of five wells. The most common reason for tripping is bit/BHA failure due to the harsh characteristics of the TF1. The CDE's unique geometry applies a concentrated point load to fracture formation more efficiently, and its ultra-thick diamond layer provides superior impact strength and wear resistance. Bits utilizing CDEs in conjunction with PDC cutters are known as CDE bits. They are able to withstand the demands of the application where conventional PDC bits cannot.
CDE bits average 5,447 ft at 83 ft per IADC hour when placed as the first bit in a lateral. That performance is 10% farther and 15% faster than conventional PDC bit offsets. Analyzing measurement while drilling (MWD) tool vibration data, CDE bits have proven to mitigate BHA vibrations compared to conventional PDC bits. These performance step changes have helped operators improve their one-bit/BHA TF1 lateral success rate from one out of five wells with conventional PDC bits to an astounding one out of three with CDE bits.
One operator in particular has utilized CDE bits to their full potential. From September 2014 to September 2015, the operator's one-bit/BHA total depth (TD) rate using conventional PDC bits was only 13%. However, the 1-bit/BHA rate when CDE bits were used was 83%, which provided a considerable savings in eliminating the nonproductive time (NPT) in tripping. Depending on the depth, a trip could cost the operator USD 80,000 and 16 hours in NPT. The average performance of CDE bit drillouts has been 9,538 ft at 137 ft per on-bottom hour, providing a 74% improvement in footage and a 2% improvement in ROP over conventional PDC bits for the operator. The reduction in NPT in tripping and improvement in drilling performance has led the operator to prefer drilling with CDE bits.
Single digit percentage of oil shale recovery leaves a large room for recovery improvement, while aqueous phase injection into shale formation is extremely challenging. Injecting Carbon Dioxide (CO2) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in the organic rich shale could permanently store CO2 volume without jeopardizing the formation integrity. This work is a study on evaluating the effectiveness of CO2 enhanced oil shale recovery and shale formation CO2 sequestration capacity. A compositional reservoir simulator is used to model CO2 injection. Petrophysical and fluid properties similar to the Bakken formation are used to set up the base model for simulation. The reservoir model considered petrophysical characteristics of shale formation that affects CO2 flow migration like in-situ stress changes, reservoir heterogeneity, and natural fractures. The results are based on sensitivity analysis of the characteristic shale petrophysical and geomechanical properties. Sensitivity analysis method analyzed all uncertain parameters together using the Design of Experiment and Response Surface Modeling approach to counter the interaction between parameters and influential parameters into generating a proxy model for optimizing oil recovery and CO2 injection into the formation. The above studies are implemented with and without geomechanical module and results are analyzed. The results show that facilitating oil recovery from shale reservoirs by CO2 injection is much higher than primary depletion depending on fracture network connectivity and geomechanical impact. Also, significant CO2 storage capacity if applicable in shale formations, will be a major step towards advances in CO2 sequestration in widely spread shale reservoirs.
Unconventional reservoir is a term to describe a hydrocarbon resource that could not be technically or economically recoverable without stimulation. Reservoir quality of tight formations is categorized as very poor because the ultra-low permeability restricts fluid movement within the reservoir. This leads to single digit oil recovery factors and costly development activities. Commercial development of low permeability, ultra-tight formations by advances in horizontal drilling and multi-stage hydraulic fracturing techniques have led to the production of significant amount of hydrocarbons. A typical production profile of an unconventional tight oil formation is illustrated in Figure 1. The high initial production rates usually attribute to hydraulic fractures, and then oil rate declines steeply once the oil near the fractured zone is produced. Beyond this rate, the flow is mainly controlled by inter-porosity mass transfer between the matrix and fracture network. In literature we studied, enhanced oil recovery (EOR) for unconventional oil reservoirs are limited.
Oil production from the Bakken formation has been active for 60 years and has applied three well-completion-design strategies in three different eras: hydraulically fractured vertical wells before 1987; horizontal wells before 1991; and multiple-transverse-fracture horizontal wells since 2006. Reported production data enable comparisons of well performance during these eras. This study employs the log-log graph of rate (q) vs. material balance time (MBT) (Q/q) to diagnose transient (Slope 2;1=4 or 2;1=2) and boundary-dominated flow (BDF) (Slope 2;1) behaviour. Wells from the three eras show mainly three types of flow-regime sequences observed as straight trends on the log-log graph of rate vs. MBT: 2;1=4 to 2;1, 2;1=2 to 2;1, and 2;1=4 to 2;1=2 to 2;1. Flow geometries corresponding to various flow-regime sequences are related to specific well and formation characteristics. Then, we extrapolate the BDF behaviour to estimate the expected ultimate recovery (EUR) for each well when possible. We observed that both the average well EUR and the average well rate at start of BDF behaviour are highest for the multiple transverse- fracture-horizontal-well completion design. This project also investigates the behaviour of the gas/oil ratio (GOR) vs. MBT. Three types of GOR behaviour were observed: constant; constant followed by sharp increase; or scattered. In all three eras, the EUR was highest in wells with constant-GOR behaviour followed by a sharp increase. The sharp increase likely signals flow below the bubblepoint pressure. The lower EUR in wells that did not produce below the bubblepoint pressure shows that solutiongas drive behaviour enhances the EUR. Lower EUR in wells with scattered GOR behaviour may be attributed to unstable well production. This study shows how to use long-term production behaviour to gain important insights describing well designs and why some wells have higher EUR and rate behaviour.
The method of stimulation employed at the Shell Groundbirch asset in the Montney tight gas play is the limited-entry slickwater hydraulic fracture. The original fracturing water specification was a simple filtering requirement and an allowable range of salinity. Considering the associated health, safety, security, and environment (HSSE) perspectives, costs, and perceptions with sourcing and disposing of water related to hydraulic fracturing, determining a fracturing water specification became critical. This paper will describe a concise and pragmatic approach for determining a new fracturing water specification and water handling system aimed at recycling flowback and produced water, while using as little fresh water as possible.
This water specification case study is based on the industry considerations of hydraulic fracturing and water management, and their impacts on costs and the environment. This approach to determine a chemistry specification for slickwater hydraulic fracturing and handling considerations may be applied elsewhere to enable the optimization of sourcing and disposal, HSSE concerns, production impairment prevention, and cost reduction.
The process of determining the water chemistry specification assessed bacteria, formation damage, scale, and friction reduction performance. After a year of consultation and experimentation, an improved, but still simple fracturing water specification was established. Chemical use includes a scale inhibitor in addition to the on-the-fly fracturing fluids of a friction reducer, a surfactant, and a biocide. Scale inhibitor usage depends on pH and iron content. Coupled with water chemistry considerations, an integrated team initiated an intrafield water handling system that first recycles flowback or produced water and uses fresh water only when brine volumes are insufficient.
This paper will specifically address (1) a method to develop a water chemistry specification for slickwater fracturing, (2) a pragmatic means of forecasting water in tight gas developments, and (3) a means of integrating water chemistry and forecasting learning into application for pragmatic field development.
Tight gas developments rely on hydraulic fracturing to produce gas at economically viable rates. One popular method of hydraulic fracturing is the limited-entry slickwater fracture treatment in which a number of perforation clusters are attempted to be simultaneously stimulated with a slickened water and proppant slurry in a number of stages throughout the wellbore. The implications of water in tight gas beyond hydraulic fracturing have been recognized at Shell Canada’s Groundbirch development in the Montney play. Shell Canada’s Groundbirch asset is located in Northeastern British Columbia, Canada, per Figure 1. The current land base consists of nearly 400 sections of Montney focused development of which about half are Shell’s land held with Brion Energy, while the remainder are held jointly between Shell and other partners.
Ely, John W. (Ely and Associates Corp) | Fowler, Steven L. (Ely and Associates Corp) | Tiner, Robert L. (Ely and Associates Corp) | Aro, Dustin J. (Ely and Associates Corp) | Sicard, Jr., George R. (Ely and Associates Corp) | Sigman, Tanner Austin (Marietta College)
Over the past 10 years Ely Corp has supervised more than 100,000 “Slick Water Fracture treatments”. After more than 30 years of dominance by extremely viscous crosslinked gels, viscous oils, emulsions and foams, the industry has in selection of fracturing fluids, moved to the point that the vast majority of fracturing fluids are either water and friction reducer or combinations of linear gel and or crosslinked gel that is very rapidly degraded to water once in the formation. In a similar time frame our industry has moved rapidly away from specific selection criteria of proppant based on strength under closure and conductivity profiles which were enhanced by both size, particle distribution, and inherent strength. The dominate proppants now used in the industry are smaller proppant such as 40/70 and 70/140 (100 mesh).
The switch to thin fluids was mainly because of intense efforts from individuals such as George Mitchell and other innovative companies who steadfastly believed in the potential of producing from virtually impermeable matrix source rock and were open to try any available technology. The switch to small proppant was driven in most cases by the lack of transport capability of the thin fluids, and in many cases due to lack of available higher strength proppant.
The success of these slick water frac fluids has, in our opinion, been due to creating a drastically different geometry combined with much larger volumes. The type of frac fluids described have been present in the history certainly since the 50’s but not with comparable rate and volume and typically not with the dominate proppant being 40/70 or smaller.
The paper will, utilizing our data base and public production data, illustrate what has truly changed the dynamic of fracturing in our industry. We will also illustrate techniques to optimize slick water fracs based on a combination of new generation technology and experience in not only source rock shale but many so called conventional reservoirs which have only now become economical with use of high volume slick water treatments where more conventional viscous fluids failed.
Based on the broad success of these fluids, we will propose a hypothesis for why these fluids and proppants, which defy conventional frac theory, have made the industry more closely evaluate even the most basic frac theories that we have followed for multiple decades.
Oil production from the Bakken formation has been active for 60 years and has applied three well completion design strategies in three different eras: mainly hydraulically fractured vertical wells before 1987, horizontal wells before 1991, and mainly multiple transverse fracture horizontal wells since 2006. Reported production data enables comparisons of well performance during these eras.
This study employs the log-log graph of rate (q) versus material balance time (Q/q) to diagnose transient (slope -¼ or -½) and boundary dominated flow (BDF) (slope -1) behavior. Wells from the 3 eras show mainly 3 types of flow regime sequences seen as straight trends on the log-log graph of rate versus material balance time: -¼ to -1, -½ to -1 and -¼ to -½ to -1. Flow geometries corresponding to various flow regime sequences are related to specific well and formation characteristics. Then we extrapolate the BDF behavior to estimate the EUR for each well when possible.
We observed that both the average well EUR and the average well rate at start of BDF behavior is highest for the multiple transverse fracture horizontal well completion design. This project also investigates the behavior of the GOR versus material balance time (MBT). Three types of GOR behavior were observed: constant, constant followed by sharp increase, or scattered. In all three eras, the EUR was highest in wells with constant GOR behavior followed by sharp increase. The sharp increase likely signals flow below the bubble point pressure. The lower EUR in wells that did not produce below the bubble point pressure shows that solution gas drive behavior enhances the EUR. Lower EUR in wells with scattered GOR behavior may be attributed to unstable well production.
This study shows how to use long term production behavior to gain important insights about well designs and why some wells have higher EUR and rate behavior.
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Western North America and Rocky Mountain Joint Regional Meeting, Denver Colorado, 16-18 April, 2014. 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.
The prediction of Estimated Ultimate Recovery (EUR) for a well or group of wells in a development project is critical to accurate reserves estimation. A number of techniques, many of which can be used deterministically or probabilistically, are employed in EUR prediction in mature and maturing unconventional gas and oil plays in North America. These include the use of geological and production data from analogous reservoirs; the use of volumetric methods and recovery factors; analytical models; numerical reservoir simulation and production decline curve analysis (DCA). Decline curve analysis is arguably the most commonly used method for forecasting reserves in unconventional reservoirs. Basic theory and application are discussed, together with the potential pitfalls of using simple empirical production forecasting methods in complex reservoirs. We analyse production data from several US unconventional oil and gas plays, and carry out production forecasting using both the traditional Arps’ methods, as a basis for comparison, and newer empirical solutions including the Power Law, Stretched Exponential Decline Model, Duong (and variations thereof). The range of production forecasts provided by these methods is examined, together with methodologies for developing statistically valid type wells in unconventional plays, and how best to determine valid input parameters for the various empirical solutions. We also examine the effect of the variable length of production history available in the various plays, and how this impacts the accuracy of our forecasts. We compare the results of these analyses with analytical models developed for each play in order to determine the suitability of each decline curve analysis method: in which plays and under which circumstances they can be applied, and suggest reasonable input parameters and data requirements for each method. Finally we discuss the potential future use of these methods in emerging plays outside of North America.