bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimized Production in the Bakken Shale: South Antelope Case Study
Authors: West David R.M. , Harkrider John , Besler Monte R. , Barham Michael , Mahrer Kenneth D
Published: November 2013

Focused modifications in drilling, reservoir, and completion engineering from 2009 to the present have improved Bakken, specifically the South Antelope Field, production as much as 50% to 75%. To achieve these results, Helis Oil and Gas Co., LLC formed a multi-disciplinary team in 2008 which it tasked with evaluating and overhauling its completion approach. Pre- 2008 completions followed conventional wisdom: target the Middle Bakken Formation between the Lodge Pole and the Three Forks Formations. Pre-2009 wellbore constructions included "kick outs" (i.e., multi-lateral), open-hole completions; short laterals; single-stage ported subs; sliding sleeves; and long stage intervals and were erratic and inconsistent. The designs and procedures resulted in a high percentage of pre-mature screenouts. In addition, the production responses on these Middle Bakken completions averaged 330 bopd with an estimated ultimate recovery (EUR) of 300 MBOe. During the pre-2009 period, 3 Three Forks were completed and these wells produced on average 550 bopd. After evaluating the pre-2009 results, the team recommended 10 changes: (1) change landing target to the Three Forks; (2) increase lateral lengths ~2x from "640’s" to "1280’s"); (3) increase formation contact (completion method, stage lateral length and, perforation spacing/density); (4) refine pump-down operations; (5) implement critical fracturing mechanisms diagnosis; (6) incorporate proppant selection (ceramic versus sand); (7) refine flush procedure to include monitoring and assure consistency; (8) integrate on-site, real-time pressure management and proppant schedule including proppant slugs, altered mesh types, and adjusted ramp schedule; (9) adjust treatment fluid design (25-lb gel loading instead of 40-lb gel loading); and (10) implement flowback and flowrate control. Implementing these recommendations, Helis deviated from conventional Williston Basin philosophy and drilled 30 "1280’s" in 2010-2012. These wells resulted in ~1,500 bopd with a maximum of 2,500 bopd and EUR’s of ~1,200 MBOe. They are among the best wells in the Williston Basin. In comparison, direct offset well EUR’s averaged less than 750 MBOe. The success of these wells is not the result of one breakthrough but rather the result of sound changes to engineering techniques that were carried out systematically. Applying these engineering practices, maintaining strict adherence to recommended practices, and not making drastic, unfounded changes ultimately optimized production in this Bakken project.
Innovative Pressure-Actuated Toe Sleeve Enables True Casing Pressure Integrity Test and Stage Fracturing While Improving Completion Economics in Unconventional Resources
Authors: Canning Sean , Pacey Kendall , Wellhoefer Ben
Published: November 2013

During the past several years, the oil and gas industry has increased the development of unconventional resource plays which are expected to hold the future for energy development in many parts of the world. In order to maximize these new reservoirs, horizontal wellbores are typically drilled, and multiple hydraulic fractures must be created to provide enough stimulated reservoir volume (SRV) to produce the wells economically. A traditional plug and perforate completion methodology has been employed to perform multi-stage fracture treatments, gain wellbore access, and isolate fracture stages. This process contains inefficiencies that can significantly impact economics. When the plug and perforate method is used prior to running perforating guns and a frac plug to depth, a flow path must be created at the toe of the wellbore. Typically, this is achieved by using tubing-conveyed perforating guns (TCP) deployed on coiled tubing (CT) or by a wireline tractor pulling perforating guns deployed on electric wireline (E-line). Although necessary, this process is one of the major plug and perforate inefficiencies noted in the above completion method. While it does allow casing pressure testing (either government-mandated or part of the operator’s well construction "best practices") prior to fracturing operations, it significantly impacts economics.

To address the inefficiencies, new technologies that seek to eliminate these problems, and thus, improve well economics are being developed. This paper explores an innovative pressure-actuated toe sleeve, which can eliminate running TCP on CT or perforating guns on E-line for initiating a flow path but still allows a casing pressure test to be run. Additionally, the pressure-actuated toe sleeve enables this casing test to be completed without having to exceed the casing test pressure to establish the flow path.

The design, testing, and use of the toe sleeve will be discussed in the paper.
A Work Method to Analyzing Friction Factors in Torque and Drag Modeling
Authors: McCormick John , Wilcox David
Published: November 2013

Long horizontal laterals with challenging well geometries and fracturing operations with 20-30 stages are commonplace in the US. Planning for successful completions operations that push the envelope of equipment and lateral reach is critical, and the ability to more accurately account for drag prior to running swell packers and frac sleeves downhole is needed to assist with the reliability of completions operations.

This paper will include an in depth look at the rig data, torque and drag models and the post job friction factors, which are an overall indication of the hole condition, for six wells. The post-job friction factors will be calibrated for drilling the final hole section and running the completions string, then analyzed to consider a link between the two operations. Production data will also be taken into account.

By creating a database of friction factors for completions operations that consider completion type, fluids used, use of centralizers, lithology and work string data, past experience has shown that even offset wells in the Bakken can have significantly varying amounts of drag. Analyzing the friction factors for drilling the final hole section will provide an opportunity to predict the level of drag prior to running the completions string.

This paper will provide the torque and drag analysis of both the drilling and completions operations for seven wells, along with a method to link the two operations. Conclusions will be drawn related to the variance between wells and the ability to predict the success of running completions strings to TD after gathering the hookload data and calibrating a post-job friction factor for the final drilled section of a well.

Although the results of the analysis will best apply to shale plays with similar geometries, the work method presented in the paper is applicable to any well construction scenario.
Integration of Numerical Simulations for Uncertainty Analysis of Transient Flow Responses in Heterogeneous Tight Reservoirs
Authors: Yue Min , Leung Juliana , Dehghanpour Hassan
Published: November 2013

The complex fracture network created by multistage hydraulic fracturing has been recently described by a triple porosity model. Existing triple porosity models typically assume sequential flow from matrix to micro fractures and from micro fractures to hydraulic fracture. Modeling simultaneous depletion of a matrix block into both micro and hydraulic fractures entails solution of a two dimensional continuity equation that is challenging by analytical or even semi-analytical methods. In addition, analysis with analytical models and type-curves provides deterministic and homogeneous estimates, rendering uncertainty analysis of fracture properties difficult.

In this paper, we use a commercial reservoir simulator to solve the transient response in a segment of a hydraulically fractured horizontal well. This is a triple porosity medium in which matrix blocks deplete into the two fracture networks simultaneously. The proposed model is used to analyze the actual rate data from a tight oil well. It is assumed that the obtained results would characterize the mean estimate of the corresponding fracture parameters. Additional heterogeneous models of fracture properties including its total number and intensity (spacing) are assigned stochastically and subjected to flow simulations to demonstrate their impact on production performance. The resulting production profiles converge to those of dual and triple porosity models at the limiting cases. Uncertainties due to pressure interference between natural fractures and inter-well fracture communication are also investigated. The variability (spread) of the simulation results would capture the sensitivity due to uncertainty in fracture distributions. Our results also show that history-matched fracture half-length strongly depends on the number of micro-fractures implemented in the static simulation model. The estimated value of fracture half-length significantly decreases by increasing the number of micro-fractures from zero, representing the dual porosity system.

This paper systematically investigates applying stochastic models of fracture heterogeneity for production data analysis. It illustrates efficient integration of numerical simulations with analytical solutions to quantify the uncertainty in production performance predictions. Information derived from this sensitivity or uncertainty analysis can be used to evaluate existing fracturing operation and to optimize future multi-stage hydraulic fracturing operations.
Geologic Controls of Gas Production from Tight-Gas Sandstones of the Late Jurassic Monteith Formation, Deep Basin, Alberta, Canada
Authors: Zambrano Liliana , Pedersen Per K. , Aguilera Roberto
Published: November 2013

Comparison of rock properties and production performance between the uppermost lithostratigraphic unit ("Monteith A") and the lowermost portion ("Monteith C") of the Monteith Formation in the Western Canada Sedimentary Basin (WCSB) in Alberta is carried out with the use of existing gas wells. The analyses are targeted to understand the major geologic controls that differentiate the two strata.

The approach involves multi-scale description and evaluation techniques of cores and drill cuttings, including multiple laboratory measurements of key reservoir parameters. The ultimate goal is to understand the distribution of reservoir quality in each stratigraphy unit within the Monteith in the study area.

This study comprises basic analytical tools available for geological characterization of tight gas Formations based on the identification and comparison of different rock types for each lithostratigraphic unit: depositional, petrographic, and hydraulic. As these low-permeability sandstone reservoirs have been subjected to post-depositional diagenesis, a comparison of the various rock types allows to generate a more accurate reservoir description, and to better understand the key geologic characteristics that control gas production potential.

It is concluded that "Monteith A" Unit has better rock quality than the Monteith C", due to less heterogeneous reservoir geometry, less complex mineralogical composition, and larger pore throat apertures. These results are linked successfully with Monteith production capabilities.
Modeling the Failure of Cement Sheath in Anisotropic Stress Field
Authors: Bui Binh T. , Tutuncu Azra N.
Published: November 2013

The primary objective of a cementing job is to create a stable mechanical link between the casing and formation. This link provides a strong support for the casing and isolates different zones to prevent any contamination to aquifers during the lifecycle of the well. The damage of the cement sheath may result in contamination of drinking water resource and negative environmental impact. Hence, the loss isolation of the cement has received much attention from researchers and the public.

The possibility of losing the isolation of the cement sheath during the lifecycle of the well is summarized and the potential risk in contaminating underground water formations is discussed in this paper. A mathematical model for predicting the failure of the cement sheath in an anisotropic stress field is presented. The model combines the effect of temperature, the variation of stress around the wellbore, internal pressure, and the integrity of the casing, cement, and rock formation. The objective of the model is to obtain the maximum internal pressure that we can apply on the casing without causing cement sheath failure. A numerical simulator was developed to calculate this maximum pressure for any inclination and azimuth angle. Computational results show that cement sheath failure depends strongly on the in-situ stress field of the surrounding formation. With stronger uniform formation support, the casing and cement can withstand larger internal stress. The failure of the cement sheath is more severe in a highly anisotropic stress field than in an isotropic field. Hence, the assumption of uniform formation stress around the wellbore may cause significant error in predicting failure of the cement sheath.

The results of this study provide petroleum engineers a tool to determine the maximum internal pressure during drilling, production and stimulation to avoid losing cement isolation. It is recommended to use this model to check the integrity of the wellbore during any operations during the lifecycle of the well.
Transitioning of Existing CO2-EOR Projects to Pure CO2 Storage Projects
Authors: Jafari Alireza , Faltinson John
Published: November 2013

The fundamental distinction between a CO2-EOR project and a CO2 Storage (CCS) project is that the former aims to maximize oil production while minimizing CO2 retention until the oil production becomes uneconomic and the project is abandoned, while the objective of the latter is to store as much CO2 as possible during and after cessation of oil production. A new transition scheme between these two main phases is proposed and described here. The objective of this transition hybrid scheme is to maximize CO2 storage while continuing oil production which otherwise would have been uneconomic. This will create additional storage space in the reservoir by producing incremental oil, with the reservoir produced water being disposed of in another formation.

A hypothetical reservoir simulation model is used to illustrate the shift over time from a conventional CO2-EOR project to a hybrid CO2-EOR/CO2 storage scheme and then to a pure CO2 storage scheme. The most common case of primary-water flood-water alternating CO2 gas (WAG) injection was simulated to mimic a typical oil pool development history. Insertion of the distinct hybrid transition phase between the end of the CO2-EOR operation and the initiation of a pure CO2 storage operation leads to an incremental oil recovery factor of approximately 9% OOIP (a function of the residual oil saturation after the end of the CO2-EOR operation). In other words, cases with the lowest recovery factor (highest residual oil) after CO2-EOR operations and just before the start of the hybrid CO2-EOR/CCS phase could potentially deliver the highest incremental oil recovery factor during this hybrid phase. More importantly, it is shown that the implementation of a hybrid scheme significantly increases the amount of CO2 storage in the reservoir, by up to 67%.

In conclusion, the advantages of having a hybrid CO2-EOR/CCS phase between the end the commercial CO2-EOR operation and pure CO2 storage phase are twofold: 1) generating oil sales revenue to offset some of the costs associated with CO2 capture, transportation and storage by delivering some incremental oil production, and 2) storing significantly more CO2 in the reservoir by creating additional voidage by producing incremental oil and water.
Anomalous Induced Seismic Deformation Associated with Hydraulic Fracturing
Authors: Maxwell S. C.
Published: November 2013

Induced seismicity resulting from fluid injection is a growing concern with a number of operations, including hydraulic fracturing. The vast majority of hydraulic stimulations results in no felt seismicity. However, three examples of larger, anomalous seismicity have been attributed to hydraulic fracturing, which seem to be associated with operations in unique geologic and geomechanical settings. In response, a number of operational protocols have been developed and include specific requirements for seismic monitoring. Seismological aspects are obviously central to these protocols, including characterizing the seismic source strength and associated seismic hazard. The typical microseismicity recorded during hydraulic fracturing represents a small portion of the hydraulic energy associated with the injection. However, the energy balance of the relative amount of seismic energy increases in the cases of anomalous seismicity, which may provide a monitoring tool to potentially help mitigate induced seismicity. Although the number of cases with anomalous seismicity is relatively small, other examples have been observed from geothermal stimulations. In these cases, the ratio of seismic energy is relatively larger but of potentially interest remains significantly less than the hydraulic energy. Furthermore, the ratio of seismic moment to injected volume also increases but typically remains less than a limit suggested by McGarr (1976). Potentially the energy and volume balances could be useful monitoring tools to assist in ongoing operation decision processes.
Fracture Cell for Flow Modeling
Authors: Sakhaee-Pour A. , Wheeler Mary F.
Published: November 2013

Hydrocarbon production from unconventional resources such as shale usually entails stimulation by hydraulic fracturing, which results in non-planar (curved) fractures. However, most reservoir models assume that the induced fractures are planar for the sake of simplicity. Considering the growing interest of the petroleum industry in better understanding production from these resources, we develop a fracture cell model to capture the effects of fracture non-planarity on transport properties.

To build a realistic reservoir model for a fractured formation, three types of interactions must be accounted for: matrixmatrix (M-M), matrix-fracture (M-F), and fracture-fracture (F-F). The transport properties of the matrix-matrix interaction (MM) are based on lab measurements. In this study, we analytically determine the transport properties of the two other types of interactions (M-F and F-F). For this purpose, we account for the aperture size and spatial location of the fracture. As a result, we provide effective porosity and effective anisotropic permeabilities for a reservoir cell that contains a fracture inside it. The reservoir cell whose transport properties are modified is a fracture cell.

We implement the fracture cell model in a reservoir simulator and perform analyses for a single fracture and for multiple intersecting fractures; these fractures are non-planar. The analyses include both single- and multiphase flow models and show that the hydrocarbon pressure inside the reservoir is strongly dependent on the fracture geometry when the matrix permeability is smaller than 1 microD. Thus, it is crucial to model the fracture geometry more accurately in unconventional reservoirs with ultra-low permeabilities such as shale.

The developed fracture cell model can easily be implemented in reservoir simulators, and there is no need for local refinement around the fracture. The main advantage of the proposed model is its simplicity, conjoined with its ability to capture the non-planarity of the fracture. The developed model has major applications for understanding production from formations that are heavily fractured.
Pseudotime Calculation in Low Permeability Gas Reservoirs
Authors: Tabatabaie S. Hamed , Mattar Louis , Pooladi-Darvish Mehran
Published: November 2013

Due to the recent advances in well design and production techniques, tight/shale gas reservoirs have received considerable attention. At the early phase of development of these reservoirs, fast analytical models are attractive since data are limited and a large number of sensitivity studies is required. This analytical solution is possible if the governing partial differential equation is linear. However, the pressure dependency of gas compressibility and viscosity makes the governing partial differential equation nonlinear. The use of pseudovariables (i.e. pseudopressure and pseudotime) significantly reduces this nonlinearity. Unlike pseudopressure, which is an exact mathematical transformation, pseudotime is an approximate transformation. For conventional gas reservoirs, the average reservoir pressure was utilized to evaluate pseudotime and worked very well during boundary dominated flow.

However, in low permeability systems, when transient flow prevails, use of average reservoir pressure for pseudotime calculation is not valid and its use can create inconsistent results. Anderson and Mattar (2007) proposed that, during transient and transitional flow, the use of average pressure within the region of influence, rather than the average pressure of the whole reservoir, results in responses that are more consistent with those from numerical simulators.

In this study, the idea of using average pressure within the region of influence is utilized to calculate pseudotime during constant rate production from a tight/shale gas reservoirs. In order to achieve this, the liquid type curve was employed to find the volume of investigation, and then the gas material balance equation was incorporated to evaluate the average pressure within the region of influence. The significant advantage of this method is that the volume of investigation is determined based on material balance principles by imposing a unit-slope line at each point in time, rather than depending on the radius of investigation formulation as was used by Anderson and Mattar (2007). In an irregularly shaped drainage area, different methods were investigated for evaluating the distance of investigation in the x- and y-directions. It was found that the distance of investigation in the x- and y- directions could not be represented by the same formula (i.e., yinv.=0.113kt/μgctϕ≠xinv. where all parameters are in field units).

The method developed in this paper is applicable in modeling different flow regimes during transient, boundary affected and boundary dominated flow periods. This paper outlines the proposed approach and explains its usefulness by comparing the analytical and numerical results for different cases. It is shown that reliable forecasts of production can be obtained.
Impact of Fluid Behavior Modification under Elevated Pressure and Temperature Conditions on Shale-Gas/Condensate Reservoir Engineering and Production Analysis
Authors: Civan Faruk , Michel Guillermo , Sigal Richard
Published: November 2013

This paper primarly focuses on the proper description of single- and multi-component hydrocarbon transport in nanoporous organic-rich shales and therefore presents the relevant issues and exploratory modeling studies to account for the effects necessary for accurate reservoir simulation. The deviation from the Darcian flow behavior of the gas/condensate transport through shale reservoirs is shown to occur mainly by alteration of fluid properties because of pore proximity effects at elevated reservoir pressure and temperature conditions although the Knudsen and Klinkenberg type corrections may involve at low pressures at later stages of hydraulically-fractured wells in shale reservoirs. A systematic methodology is presented for modification of the fluid and phase behavior relevant to transport at elevated pressure and temperature conditions. The modifications of the phase diagram, density, viscosity, and surface tension for typical hydrocarbon components and mixtures in various size pores reduced further by adsorbed components layers are compared with those of the bulk systems. Further, the role of organic connectivity in shales characterized by organic and inorganic nanopores on production from shale wells is investigated. The role and performance of isolated organics in the form of a ‘raisin-bread’ model in comparion with organics that are organized in slabs with relatively longer correlation lengths are demosntrated by simulation. The methodology for haldling of the organic connectivity and the pore-proximity effects on fluid properties provided here may be instrumental for accurate shale gas and liquids-rich shale reservoir simulation.
Novel Controlled Pressure Coring and Laboratory Methodologies Enable Quantitative Determination of Resource-in-Place and PVT Behavior of the Duvernay Shale
Authors: Davis M. , Williams R. , Willberg D. , Bjorum Matt , Akbarzadeh Kamran
Published: November 2013

The North American hydrocarbon supply market has been transformed by recent discoveries in regionally continuous reservoir units consisting of shale and tight sands. Effective porosity values in these reservoirs average as low as 2% to 6% with nanoDarcy permeability in situ. Classical means of determining resource-in-place values in these unconventional formations involves integrating core and log analysis methodologies, where numerous levels of uncertainty exist. Controlled pressure coring operations were conducted on a sequence of wells drilled into various maturity windows in the rapidly emerging liquids-rich Duvernay Shale through the course of 2011 and 2012. Capturing critical resource-in-place parameters and conducting quantitative analysis of volatile hydrocarbons contained within the cored interval required the development of new field and laboratory methodologies. These procedures represent the only currently available workflow capable of directly capturing and analyzing reservoir hydrocarbons from core material. Field operations and core preservation steps were developed to maintain the integrity of the hydrocarbon system during shipping and core processing. Additionally, a laboratory methodology was developed for preserving and extracting liquid hydrocarbons from core material. By quantitatively recombining these extracted fluids with volatile hydrocarbons captured from the controlled pressure coring operation, in situ PVT behavior of this single-phase volatile oil/condensate reservoir can be determined. As a result, recombined fluids can be compared to production samples for the purpose of studing pore scale mechanisms affecting production. Key breakthroughs were made during all stages of the workflow, and it was determined that core capture and surface handling operations are just as important as developing the new laboratory techniques required to understand resource uncertainty, effective fluid mobility, and PVT behavior. This paper describes and documents the key advancements made in coring operations and specialized core analysis, as well as their role in accurate quantification of hydrocarbons in place and the determination of in situ PVT behavior of the Duvernay Shale.
Hydrocarbon Mobilization Mechanisms from Upper, Middle, and Lower Bakken Reservoir Rocks Exposed to CO2
Authors: Hawthorne Steven B. , Gorecki Charles D. , Sorensen James A. , Steadman Edward N. , Harju John A. , Melzer Steve
Published: November 2013

Efforts to increase Bakken oil recovery factors above a few percent could include carbon dioxide (CO2) enhanced oil recovery (EOR). CO2 EOR processes are expected to be very different in tight reservoirs compared to conventional reservoirs. During CO2 EOR in conventional reservoirs, CO2 flows through the permeable rock matrix, and oil is mobilized by a combination of oil swelling, reduced viscosity, hydrocarbon stripping, and CO2 displacement especially when above the minimum miscibility pressure. In the Bakken, CO2 flow will be dominated by fracture flow, and not significantly through the rock matrix. Fracture-dominated CO2 flow could essentially eliminate the displacement mechanisms responsible for increased recovery in conventional reservoirs. As such, other mechanisms must be optimized in tight reservoirs such as the Bakken.

Conceptual steps for the Bakken include: (1) CO2 flows into and through the fractures, (2) unfractured rock matrix is exposed to CO2 at fracture surfaces, (3) CO2 permeates the rock driven by pressure, carrying some hydrocarbon inward; however, the oil is also swelling and extruding some oil out of the pores, (4) oil migrates to the bulk CO2 in the fractures via swelling and reduced viscosity, and (5) as the CO2 pressure gradient gets smaller, oil production is slowly driven by concentration gradient diffusion from pores into the bulk CO2 in the fractures.

To investigate these concepts, rock samples from the Middle Bakken (low permeability), Upper and Lower Bakken (very low permeability), and a conventional reservoir (high permeability) were exposed to CO2 at Bakken conditions of 110°C and 5000 psi (230°F, 34.5 MPa) to determine the effects of CO2 exposure time on hydrocarbon production. Varying geometries of each rock ranging from small (mm) "chips" to 1 cm-diameter rods were exposed for up to 96 hours, and mobilized hydrocarbons were collected for analysis. Nearly complete (>95%) hydrocarbon recovery occurs in hours from the middle Bakken reservoir rock, and even faster with the more permeable conventional matrices. Unexpectedly, nearly complete recovery of hydrocarbons can even be achieved from the very tight source shales from the Lower and Upper Bakken, but requires longer exposure times and smaller rock sample sizes (i.e., high surface area to volume ratio). These results demonstrate that CO2 is capable of recovering hydrocarbons from Bakken source and reservoir rock (i.e., the thermodynamics of CO2 oil recovery are favorable), but that long periods of exposure combined with high rock surface areas are required (i.e., the kinetics of the recovery process are slow). The present study reports experimental methods and the resultant data to investigate the proposed mechanisms that will control CO2 EOR in tight formations. Implications for CO2 EOR processes in unconventional reservoirs are discussed.
Integrated Analysis of Core Geology, Rock Properties, Well Logs, and Seismic Data Provides a Well Constrained Geologic Model of the Bossier/Haynesville System
Authors: Suarez-Rivera Roberto , Herring Shanna , Handwerger David , Marino Sonia , Petriello John , Stevens Kimberly
Published: November 2013

In unconventional reservoirs, the drivers of reservoir quality and hydrocarbon producibility are mostly evident at the scanning electron microscope (SEM) scale. For field applications, the practical scales of observation have resolutions from few feet to tens of feet. Finding ways of integrating the two scales allows propagation of knowledge, obtained at SEM and core scale, across the field. This is achieved via strong understanding of rock texture and composition, and of the geologic processes that defined them. The objective is to understand the rock, via detailed geologic and petrologic core studies, and define ways to identify core-scale rock texture and composition with well log and seismic measurements.

We define the depositional and diagenetic transformations that occurred in the various facies of the Haynesville and Bossier system using core geologic and petrologic studies. We identify the different textural and compositional properties that define these facies and, by selecting a log suite sensitive to texture and composition, investigate their ability to discriminate these differences. We use a core-log model to predict the distribution of these geologic facies in other regions of the field, and validate these predictions with additional core studies in these regions. The potential and limitation of the log responses to identify subtle changes in rock texture and composition is critical to this effort. Once validated, the log-scale model is filtered to seismic resolution, and used to map geologic units at the seismic scale.

The log-scale measurements detect sequences of the core-scale facies, thus allowing us to map their presence and distribution across the play. The method improves field geologic characterization, defines an efficient selection criterion for additional science wells with core and for selection of additional seismic data.

Core-log integration was successful across a region of 7,185 square miles, and core-log-seismic integration was successful across a region of 200 square miles. The method provided a cost efficient concept for exploration, and for tying the varying geologic processes in the basin to the resulting conditions of reservoir quality and production potential. It also provided information for more effective well placement design.
Lessons Learned from Shell's History of Casing Conveyed Fiber Optic Deployment
Authors: Bateman K. , Molenaar M. M , Brown M. D.
Published: November 2013

Fiber Optic Sensing is an emerging technology that can provide a means to measure a broad range of downhole events that span geophysics, completion and production engineering applications. All these measurements can be performed by installation of a single fiber optic cable; assuming reliability and life-cycle cost(s) are sufficiently robust. The multiple applications of fiber optic technology provide an effective way to maximize data collection from a single well. This data can result in a better understanding of the subsurface, which can help make more efficient and effective commercial and development decisions.

For the Unconventional Gas and Light Tight Oil projects, Shell has completed a number of wells across North America with fiber permanently conveyed on the outside of the production casing and across the completion interval for the primary purpose of capturing hydraulic fracture (HF) stimulation data. Multiple fibers can be deployed in a single cable, enabling simultaneous data gathering from distinct optical technologies. As such, the installed fibers have also been used to detect micro-seismic events, capture VSP data, and to analyze stimulation flow-back and production inflow profiles.

In order to fully realize the potential of fiber optic technology for the multiple applications, it is necessary that the fiber optics remain operational for a sufficient length of time to gather the desired data sets over the well life. This has proven quite challenging in this severe environment: often fiber optic cables fail prematurely during, or shortly after, deployment or during HF stimulation operations. These failures have been categorized into three general groups: downhole, surface, and supporting data collection systems.

Before this technology can fully mature, it is critical that the current reliability issues are addressed. This paper will study the status of Shell fiber wells across North America, illustrate the temperature and acoustic response when a fiber fails during HF stimulation, and share the results of reliability testing on several different fiber optic cable designs.
How to Estimate Water Saturation Exponent In Dual and Triple Porosity Reservoirs With Mixed Wettability
Authors: Olusola Bukola K. , Aguilera Roberto
Published: November 2013

Mixed wettability is a common concern in heterogeneous reservoirs. The problem from a practical point of view is the general lack of water saturation exponent (n) laboratory values in rocks with mixed wettability.

To contribute to the solution of this concern, we utilize electromagnetic mixing rules to develop a new petrophysical model capable of estimating the water saturation exponent (n) and water saturation (Sw) in heterogeneous reservoirs with mixed wettability. The reservoirs are represented by dual porosity (matrix and fractures or matrix and isolated porosity) and triple porosity (matrix, fractures, and isolated porosity) models. Results from the models developed in this work compare well with core data.

We have used the same electromagnetic mixing rules in the past for successful determination of the porosity exponent (m) in heterogeneous reservoirs. The addition in this paper offers a means for calculating the water saturation exponent (n) and makes the electromagnetic mixing rules a powerful tool for complete formation evaluation of heterogeneous reservoirs with complex pore structures and mixed wettability.

It is concluded that the new petrophysical models developed in this study provide a significant contribution to the determination of water saturation exponent (n) and water saturation (Sw) in rocks with mixed wettability and hence lead to improved values of hydrocarbon in place estimates.
A Case Study on Formation Evaluation of Horizontal Wells in the Tight Gas Nikanassin Group of the Western Canada Sedimentary Basin Using Drill Cuttings
Authors: Olusola Bukola K. , Aguilera Roberto
Published: November 2013

The use of drill cuttings has evolved recently from qualitative to quantitative evaluations due to the possibility of measuring porosity and permeability from drill cuttings in the laboratory with a good level of certainty. One of the advances has been the implementation of complete quantitative formation evaluation for vertical wells from drill cuttings only in the absence of well logs.

This paper uses the same methodology in the case of a horizontal well. The case study is demonstrated with the use of sixty five (65) drill cuttings samples collected over 760 meters of a horizontal well drilled through the Monteith formation, Nikanassin group of the western Canada sedimentary basin (WCSB).

Starting with only drill cuttings measurements of porosity and permeability in the laboratory, the method allows a successive approach for determination of several parameters of interest including pore throat aperture radius, water saturation, porosity exponent (m), true formation resistivity, Knudsen number, capillary pressure, construction of Pickett plots, and the estimation of geomechanical properties such as Young Modulus, Poisson’s ratio and brittleness index throughout the horizontal length of the well.

And for those cases where there is close to no data at all in the Nikanassin formation, empirical correlations have been developed for estimating Poisson’s ratio, static Young Modulus and brittleness index with the use of only porosity from drill cuttings. The correlation coefficient (R2) in this case is 0.99.

It is concluded that drill cuttings provide a useful direct source of information for quantitative formation evaluation of horizontal wells particularly in those cases where core and log data are scarce.
Performance Evaluation of CO2 Huff-n-puff Processes in Tight Oil Formations
Authors: Song Chengyao , Yang Daoyong
Published: November 2013

Techniques have been developed to experimentally and numerically evaluate performance of CO2 huff-n-puff processes for unlocking resources from tight oil formations. Experimentally, core samples collected from a tight formation with a permeability range of 0.27-0.83 mD are used to conduct a series of coreflooding experiments. The performance of four recovery schemes, i.e., waterflooding, immiscible CO2 huff-n-puff, near-miscible CO2 huff-n-puff, and miscible CO2 huff-n-puff processes, is evaluated with the tight core samples. The waterflooding process leads to a higher oil recovery factor in comparison with the immiscible CO2 huff-n-puff process, while both the near-miscible and miscible CO2 huff-n-puff processes result in higher recovery efficiency compared to that of waterflooding. Theoretically, numerical simulation is performed to match the experimental measurements obtained in the different recovery schemes. There exists a generally good agreement between the experimental measurements and simulated results. The tuned numerical model is then employed to optimize the injection pressure and soaking time during CO2 huff-n-puff processes. It is found that the optimum injection pressure of the CO2 huff-n-puff process can be set around the minimum miscibility pressure (MMP) between crude oil and CO2, while the soaking time can be optimized for maximizing oil recovery.
Effects of Non-Darcy Flow and Penetrating Ratio on Performance of Horizontal Wells with Multiple Fractures
Authors: Zhang Feng , Yang Daoyong Tony
Published: November 2013

A novel slab source function has been formulated and successfully applied to examine effects of non-Darcy flow and penetrating ratio on performance of a horizontal well with multiple fractures in a tight formation. The Barree-Conway model is incorporated in the mathematical model to analyze non-Darcy flow behaviour in the hydraulic fractures, while the pressure response under non-Darcy flow is determined by two dimensionless numbers (i.e., relative minimum permeability (kmr) and non-Darcy number (FND)). More specifically, such a slab source function in the Laplace domain has assigned a geometrical dimension to the fracture. A semi-analytical method is then applied to solve the newly formulated mathematical model by discretizing the fracture into small segments. The newly developed function has been validated with numerical solution obtained from a reservoir simulator. Non-Darcy effect becomes more evident at a smaller relative minimum permeability (kmr<0.05) and a larger non-Darcy number (FND>10). The non-Darcy number is found to be more sensitive than the relative minimum permeability, resulting in a larger pressure drop even at a larger kmr. In addition, the non-Darcy flow is found to impose a significantly impact on the early-stage bilinear/linear flow regime, resulting in an additional pressure drop that is similar to lowering the fracture conductivity. The pressure response can be classified into two categories by a penetrating ratio of 0.5. When the penetrating ratio is decreased, the early bilinear/linear flow regime occurs, followed by an early radial flow regime.
Multi-Porosity, Multi-Permeability Models for Shale Gas Reservoirs
Authors: Haghshenas B. , Clarkson C. R. , Chen S.
Published: November 2013

Numerical simulations are commonly used for studying and forecasting the production from conventional reservoirs. However, limitations of the Darcy’s equation have been noted for shale gas reservoirs due to the complexities associated with nano-scale pores, organic-rich heterogeneous rocks, and extremely-low permeability. In addition, the classical dual porosity/permeability models do not adequately describe the complex physics and dynamics in shales.

This paper utilizes a novel multi-porosity, multi-permeability model in a commercial simulator, incorporating the structural details of shale reservoirs. The generated models account for the storage capacity of shales by mapping three different porosity systems (i.e., organic, inorganic, and natural fractures) with guidance from recent results of microscopic petrophysical studies such as SEM, TEM, and SANS/USANS. Desorption is set to be active only in organic matter. To capture different transport controls in reservoirs with an overwhelming number of fine pore throats, the models include three different permeability conduit networks including organic and inorganic matrix, and natural fractures. Physical properties contributing to flow capacity such as formation wettability are set to be optionally active in corresponding zones. We also consider the diffusion effect in shale matrix grids based on pore size distribution.

Three configurations are used to investigate the connectivity among the three porous systems and the impact of each configuration on ultimate recovery of gas is evaluated. In Configuration 1, an interconnected organic pore system (which feeds the natural fracture system) is largely independent of the inter-granular matrix pore system. However, Configuration 2 assumes that the organic pores feed the inorganic matrix pore system which in turn feeds the fracture system. In Configuration 3, the organic and inorganic pore systems feed the natural fractures in parallel.

The results of this study demonstrate that the selected pore connectivity configuration has a significant impact on shale gas production, underscoring the need to carefully choose the configuration to match pore-scale observations.
Diffusion and Flow Mechanisms of Shale Gas through Matrix Pores and Gas Production Forecasting
Authors: Shi Juntai , Zhang Lei , Li Yuansheng , Yu Wei , He Xiangnan , Liu Ning , Li Xiangfang , Wang Tao
Published: November 2013

The transport mechanism of gas moving through matrix pores is the bottleneck of conquering the difficulties in shale gas development. The matrix pores can be divided into organic and inorganic matrix pores. The transport mechanism of shale gas in organic and inorganic matrix pores is different. However, the present gas transport model only focused on the gas transport in organic matrix pores, in addition, the impact of organic and inorganic mass ratio has been largely neglected by shale gas transport models in the literature, leading to an unclear recognition of shale gas production discipline and large derivation between prediction results by the present models and actual performance of shale gas wells.

In this paper, both the pore size distribution and water distribution in shale matrix pores are investigated. Furthermore, a new diffusion-slippage-flow model in combination with the gas transport mechanism is proposed. Also, the organic content effect is considered and the range of Knudsen number is quantified. Finally, a gas production model based on this gas transport mechanism is derived and employed to reveal the discipline of shale gas production.

The preliminary results illustrate that Knudsen diffusion is not suitable for shale gas reservoirs. This is because Knudsen number is generally less than 10, especially for such shale gas reservoirs with higher initial reservoir pressure. Gas moving through shale matrix pores to fractures is mainly divided into two forms: in organic matrix pores, both slip effect and transition diffusion mechanism are dominant; in inorganic matrix pores, the gas-water two-phase flow controls the gas transport mechanism because of the presence of water in these pores.

The efforts of this work will provide a more accurate technique for forecasting shale gas production, and also give some insights into scientific evidence to the rational development of shale gas reservoirs.
A New Coring Technology to Quantify Hydrocarbon Content and Saturation
Authors: Bjorum Matt
Published: November 2013

The industry is challenged to accurately determine the total hydrocarbon composition and saturations in both conventional and unconventional reservoirs. Several attempts in coring technology advances have been employed in the past with limited success. These attempts include methods to collect expelled pore space fluids and gases for further analysis. The attempts have resulted in technologies that provide limited core in terms of length and diameter, low recovery percentages, poor success ratios and complicated core processing. Pressure coring itself has been viewed as a solution but introduces inherent safety concerns by bringing high-pressure systems to the surface. The combination of poor reliability and safety risks has resulted in infrequent use of the various technologies and methods to analyze pore fluids and gases. A new tool has been developed to overcome the safety concerns, simplify core processing and provide the means for quantitative answers.