The difficulty in obtaining a continuous rock elastic properties (REP) profile from triaxial test makes calibration of geomechanical characterization models subjective. The impulse hammer method however provides reliable, reproducible, and continuous proxy for REP dataset, allowing for rock profiling. The relationship between the REP from these two techniques is not well understood, this study employed multivariate data reduction analysis and modeling to extract relevant correlations between Impulse Hammer and Triaxial derived REP. We derived a Young's modulus proxy called reduced Young's modulus (E*) from core plug samples. The E* was acquired from each sample systematically with respect to rock heterogeneity, grain size, and macropore size. The E* was taken as an average of nine impulse hammer runs per sample on equally spaced gridded location on each sample surface. Dynamic Young's modulus (Ed) and static Young's modulus (Es) were derived from the conventional triaxial test. The geochemical analyses were carried out to capture the mineralogical variations in the selected samples. We used statistical analysis and modeling to establish empirical relationship between Impulse Hammer and Triaxial derived RMP.
The results showed that, E* reliably captures the variables within the rock elastic properties. A strong correlation between the Ed, Es, and E* were observed in the samples. We also observed that E*, reveals details of several geomechanical heterogeneity and anisotropy which are not possible with traditional triaxial method. The results show that the empirical relationship between E and E* can be established to generate a continuous REP profile.
Sample availability, representativeness, time, and cost are common challenges in traditional triaxial test. The Impulse Hammer method is a non-destructive technique that significantly saves time, and has a promising cost efficient workflow, which provides reliable, reproducible and continuous rock mechanical properties profile. A robust geomechanical characterization and model calibration can be performed by combining the outputs obtained from these two methods.
This case study helped an operator in the Powder River Basin approach an optimized completion design. The operator used geomechanical measurements, hydraulic fracture modeling, and fracture diagnostics on two horizontal wells. The two wells are near a previously-completed, producing well (i.e., “parent” well).
While drilling the two horizontal wells, the operator acquired geomechanics data. This method, called drill bit geomechanics, measured the variability along the laterals. These data produced geomechanically-informed perforation and stage placements to minimize the differences in minimum horizontal stress across each stage. Additionally, the operator engineered the perforation sizes, which increased perforation friction to overcome the measured variability. The authors used the near-wellbore geomechanics data, along with other data, in a hydraulic fracture simulator. In general, standard hydraulic fracture simulators assume constant mechanical properties in each geologic layer. Compared to this standard practice, adding measured geomechanics data can more accurately predict which perforation clusters may be stimulated. To test two different fluid systems, the operator designed a “hybrid” (i.e., combination of slickwater and crosslinked gel) treatment for Well 1 and a slickwater treatment for Well 2. Fracture diagnostics reported their effectiveness. Diagnostics included: 1) proppant tracers to evaluate the perforation efficiency, 2) oil-soluble fluid tracers to quantify by-stage production contribution, and 3) water-soluble fluid tracers to assess inter-well communication. Also, the operator had used proppant tracers on the parent well, providing a baseline for results comparison.
Compared to the parent well, the two study wells showed 15-22% higher perforation efficiency. This suggests the engineered design changes created more even proppant distributions. Understanding the geomechanical variability, the operator recognized the engineering required to overcome it. The oil-soluble tracer, although affected by the parent well's depletion profile, showed higher perforation efficiency can increase oil production. Between the two study wells, Well 1 had higher perforation efficiency than Well 2 and it slightly out-produced Well 2. This suggested the hybrid design was likely the more effective design. The hydraulic fracture simulator with near-wellbore geomechanics data predicted perforation efficiency similar to that measured by the proppant tracer. Across both wells’ traced stages, the predicted efficiency and measured efficiency were within 3%. The measurements validated the modeling method.
This paper describes a method of improving completion designs through 1) geomechanics data measured while drilling, 2) modeled perforation cluster efficiency, 3) a measurement of proppant placement effectiveness, and 4) an estimate of stage-by-stage production. For the Powder River Basin operator, this method informed decisions about the next completion design iterations. Operators in any unconventional basin could apply this workflow to approach an optimized completion.
Shale has been usually recognized as a transverse isotropic (TI) medium in conventional geomechanical log interpretation due to its laminated nature. However, when natural fractures (NFs) exist in the rock body, additional elastic anisotropy can be introduced, converting laminated Shale to an orthorhombic (OB) medium. Previous studies illustrate that treating the naturally fractured shale rock as a TI medium by ignoring the NF-induced anisotropy can cause the erroneous estimation of the geomechanical properties and in-situ stress. In this paper, the study is extended to quantify the impact of NF-induced elastic anisotropy on completion and fracturing designs in different actual shale reservoirs in U.S.
Published acoustic log data from five different shale formations (Bakken, Marcellus, Haynesville, Eagle Ford, and Niobrara) are collected and examined to determine their availability to generate the stiffness tensor of the representative TI background rock of each Shale reservoir. Natural fractures with different intensity values from 0 to 10 per foot, with shear wave splitting ranging from 0-5%, are introduced in the TI background rock to create the corresponding OB rock stiffness tensor. The OB stiffness tensors of different shale cases are finally converted back to the compressional and shear acoustic signals, which can be interpreted based on the TI or OB assumptions. The final output elastic moduli and in-situ stress results interpreted from different assumptions are compared, and the impact of NF-induced elastic anisotropy on completion and fracturing designs is quantified and fully understood for different shales.
The results show that introducing natural fractures into the TI background shale rock leads to a decrease of the in-situ stress and Young's modulus at the orientation perpendicular to the natural fracture plane. Such impact increases with increasing split of fast and slow shear wave slowness (SWS), while decreases with increasing ratio of the “soft mineral content” (i.e. clay and TOC) to the “hard mineral content” (i.e. quartz and calcite). In addition to that, different impacts on stress contrast (variation along the vertical depth) are observed for different shales, owing to the complex mineralogy/lithology sequences of different shale formations. As a result, ignoring the natural fracture induced elastic anisotropy in acoustic log interpretation can result in an overestimation of in-situ stress and Young's modulus as well as a misinterpretation of stress contrast, which further leads to the problematic or suboptimal completion/fracturing designs. The results have been also compared with the shale mineralogy/lithology log data to reveal how the natural fracture induced elastic anisotropy impact is associated with the natural fracture properties (compliance and intensity) and the mineralogy of TI background rocks.
The current study not only illustrates the importance of taking natural fracture induced anisotropy into account when performing geomechanical log interpretation, but also provides guidance to the operators of the five shale fields to better evaluate their current completion/fracturing design strategies and to determine if the natural fracture induced anisotropy impact should be corrected for their current designs or not based on the monitored splitting of fast and slow shear wave slowness.
The Finn-Shurley field produces petroleum from the Upper Cretaceous Turner Sandstone of the Powder River Basin. The Turner is a member of the Carlile and is overlain by the Sage Breaks and underlain by the Pool Creek members of the Carlile. The Turner is interpreted to be a shallow marine shelf sandstone deposited along the eastern side of the Western Interior Cretaceous Seaway. Sand-shelf-bar orientation across the field is roughly east-west. Trapping occurs where sandstone beds get shalier up-dip. The field is located along the shallow east margin of the Powder River Basin south of the Clareton lineament.
Three to four coarsening upward cycles are present in the Turner in the field. Most of the production in Finn-Shurely comes from the lower two cycles. Each cycle consists of burrowed to bioturbated, heterolithic mudstones and sandstones coarsening upwards into fine-grained laminated to burrowed sandstones. Trace fossil present fall into the shelf Cruziana ichnofacies. The sandstones are largely litharenites. Porosities range from 11-17% and permeabilities range from 0.06 to 0.5 md. Source rock analysis of the Turner shales indicate Ro values averaging 0.63 and Tmax values of 433°C. Source beds for the oil and gas in the Turner are thought to be the Mowry and Niobrara formations. The low thermal maturity suggests lateral migration of oil into the stratigraphic trap.
The field extends over an area roughly circular in shape of ~65 square miles. Productive depths across the field are 4450 to 5700 ft. First production is reported as 1965 and cumulative production from ~750 vertical wells is 23.6 MMBO and 38.9 BCFG. Cumulative gas oil ratio is 1688 cu ft gas per barrel oil. Average production per well is approximately 31.5 MBO and 52 MMCFG. Horizontal drilling activity in the field area has recently commenced. Although the production is fair to marginal, the field provides an excellent example of trapping style as well as a depositional model for Turner Sandstone elsewhere in the Powder River Basin. Recent drilling in the deeper overpressured parts of the Powder River Basin has encountered excellent production from the Turner (> 1,000 bbls oil equivalent per well).
Finn-Shurley Field is part of a continuous accumulation within the Turner Sandstone in the Powder River Basin. Distinct oil-water contacts are not present in the field area. The accumulation is underpressured and regarded as unconventional.
A challenge in oil-reservoir studies is evaluating the ability of geomechanical, statistical, and geophysical methods to predict discrete geological features. This problem arises frequently with fracture corridors, which are discrete, tabular subvertical fracture clusters. Fracture corridors can be inferred from well data such as horizontal-borehole-image logs. Unfortunately, well data, and especially borehole image logs, are sparse, and predictive methods are needed to fill in the gap between wells. One way to evaluate such methods is to compare predicted and inferred fracture corridors statistically, using chi-squared and contingency tables.
In this article, we propose a modified contingency table to validate fracture-corridor-prediction techniques. We introduce two important modifications to capture special aspects of fracture corridors. The first modification is the incorporation of exclusion zones where no fracture corridors can exist, and the second modification is taking into consideration the fuzzy nature of fracture-corridor indicators from wells such as circulation losses. An indicator is fuzzy when it has more than one possible interpretation. The reliability of an indicator is the probability that it correctly suggests a fracture corridor. The indicators with reliability of unity are hard indicators, and “soft” and “fuzzy” indicators are those with reliability that is less than unity.
A structural grid is overlaid on the reservoir top in an oil field. Each cell of the grid is examined for the presence and reliability of inferred fracture corridors and exclusion zones and the confidence level of predicted fracture corridors. The results are summarized in a contingency table and are used to calculate chi-squared and conditional probability of having an actual fracture corridor given a predicted fracture corridor.
Three actual case studies are included to demonstrate how single or joint predictive methods can be statistically evaluated and how conditional probabilities are calculated using the modified contingency tables. The first example tests seismic faults as indicators of fracture corridors. The other examples test fracture corridors predicted by a simple geomechanical method.
Khan, Khaqan (Saudi Aramco) | Almarri, Misfer (Saudi Aramco) | Al-Qahtani, Adel (Saudi Aramco) | Syed, Shujath Ali (Baker Hughes, a GE Company) | Negara, Ardiansyah (Baker Hughes, a GE Company) | Jin, Guodong (Baker Hughes, a GE Company)
Rock mechanical properties are required as an input in many petroleum engineering applications, such as borehole stability analysis, hydraulic fracturing design, and sand production prediction. Their determination is commonly from various laboratory testing performed on subsurface rock samples. Due to the scarcity of reservoir samples and test cost, rock mechanical data are always very limited. Therefore, empirical correlations are very often used to estimate the mechanical properties from downhole logging measurements. Alternatively, the data-driven analytics techniques have been developed for predicting rock properties from other formation properties that can be determined directly from logs.
This paper presents a study of developing correlation equations and data-driven models that are used to predict the unconfined compressive strength (UCS) from logging data. Various rock mechanical tests including UCS, single- and multi-stage triaxial tests are performed on sandstone samples from three wells in one region. UCS values are obtained either from the UCS testing directly or from the Mohr-Coulomb failure analysis indirectly. Rock properties, such as mineralogy, porosity, grain and bulk density, ultrasonic wave velocities, are measured for each tested sample, which are used to build the correlations and data-driven analytical models for predicting UCS. Results shows that the empirical correlations are not universal and often cannot be used without some modifications, while the data-driven model is more generalized in application. In addition, data quality is very crucial for building correlations or predictive models.
Agarwal, Karn (Liberty Oilfield Services) | Kegel, Justin (Ballard Petroleum, LLC) | Ballard, Bryce (Ballard Petroleum, LLC) | Lolon, Ely (Liberty Oilfield Services) | Mayerhofer, Michael (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services) | Melcher, Howard (Liberty Oilfield Services) | Compton, Sarah (Liberty Oilfield Services) | Turner, Paul (Liberty Oilfield Services)
As the Powder River Basin (PRB) development continues and more wells are drilled, identifying best completion practices is critical to economic success. This operator has completed several Turner horizontal wells drilled at 10,300-11,000 ft TVD using crosslinked gel with encouraging results. Although reservoir quality varies in the basin, the Turner interval is more than 30 ft thick in the area of interest (AOI) in Campbell County, Wyoming. In this area, production history matched permeability ranges from 0.005 to 0.1 mD, with pore pressure gradient from 0.55 to 0.64 psi/ft. Fracture modeling and production history matching/sensitivities were performed on a few horizontal wells. This paper discusses the results of this modeling and history matching, and it summarizes the evolution of Turner Formation fracture treatment designs, that were done by one operator to maximize the return on investment.
The operator collected core data, open hole logs, and Diagnostic Fracture Injection Test (DFIT) data. The objectives of this study were to: a) determine reservoir parameters from DFIT, b) estimate fracture height growth, fracture half-length, and conductivity for Turner crosslinked gel fracs, c) determine the most appropriate perforation cluster or fracture spacing, as well as treatment rate, fluid/proppant loading, and proppant types/sizes based on the expected long-term production performance, d) compare the estimated production of cemented sleeve vs. plug-and-perf completions, and e) perform multivariate analysis of public production and completion data to compare with the detailed physical modeling.
The results presented in this paper show well-performance predictions as a function of sleeve/perforation cluster spacing, treatment size, proppant type, mesh size, and pump rate. Implications for implementation of a certain treatment and completion design are discussed in detail.
Rathnaweera, Tharaka D. (Monash University /Nanyang Technological University) | Gamage, Ranjith P. (Monash University) | Wei, Wu (Nanyang Technological University) | Perera, Samintha A. (The University of Melbourne) | Haque, Asadul (Monash University) | Wanniarachchi, Ayal M. (Monash University) | Bandara, Adheesha K. (Monash University)
Over the last several decades, many studies have generated a large amount of proppant performance data, but these studies have only focused on proppant conductivity, with no attention to how proppant mechanical properties vary under loading conditions. The impact of mechanical behaviour on proppant performance can only be fully understood by the combined investigation of micro-structural and mechanical changes with increasing loading. Therefore, this study aims to identify such micro-structural behaviour, and in particular the impact on proppant mechanical properties. Proppant samples were tested under one-dimensional compression loading using high-resolution X-ray CT scanning technology. The reconstructed images taken at different load stages were analysed to capture the micro-structural behaviour and finally correlated with the mechanical behaviour of the proppant.
According to the results, there are significant micro-pore voids inside the proppant mass. When the proppant has a higher degree of porosity, there is a considerable reduction of the compressive strength which is not favourable for hydro-fracturing treatment designs. Moreover, it is clear that the brittleness of the proppant decreases with increasing porosity, as its Young’s modulus reduces with increasing pore voids. Therefore, it is important to have high manufacturing standards to achieve effective proppant performance at great depths. The micro-structural behaviour under increasing loading was investigated by performing comprehensive CT image analysis using Drishti software. According to the results, under compressive loading, proppants cleave and generate large fragments like a flower, and this happens suddenly and quite violently through the material. Interestingly, post-failure analysis revealed that the failure mechanism of a single proppant consists of three major stress levels, where initially proppant fails at a high stress level and gains some crushing-associated strength at later stages.
Unconventional oil/gas production has recently attracted the research community due to the uncontrollable increasing demand for primary energy sources (Perera et al., 2016; Wu et al., 2017). Since this method provides a good solution to energy scarcity, over the last several decades, the industry has tried to enhance the production rate, mainly focusing on production enhancement techniques which can be effectively used in the energy extraction from sub-surface geological formations. Of the various options, hydraulic fracturing is one of the best ways to enhance oil/gas extraction, as it increases the formation’s permeability, allowing easy movement of the extracted oil/gas towards the production well (Rutledge and Scott, 2003; Orangi et al., 2011; Vengosh et al., 2014; Wanniarachchi et al., 2015). However, this process may be jeopardised due to the high stress levels acting on the formation at great depths (both vertical overburden and confining pressures). One possible consequence is re-closure of the fracture network under downhole stress conditions, which severely affects the post-fracturing production. Such issues can negate the use of proppant as a hydraulic fracture treatment method where proppants injected with the fracturing fluid prop the fractures, withstanding the fracture-closure stress (Wanniarachchi et al., 2015). Although the proppant gives a reliable solution to overcome this issue (propping the fracture network), sufficient closure stress can cause mechanical failure of the proppant, changing the fracture conductivity, causing re-closure of the fracture network, and altering the bulk properties of the proppant pack, which can negatively influence oil/gas extraction. Therefore, it is important to understand the mechanical behaviour of proppants under downhole stress conditions before injecting proppant with the hydro-fracturing fluid.
Li, Junfei (CNOOC Ltd, Tianjin Branch) | Liu, Xueqi (PetroChina Research Inst. Petroleum Exploration and Development) | Gao, Zhennan (CNOOC Ltd, Tianjin Branch) | Shang, Baobing (CNOOC Ltd, Tianjin Branch) | Xu, Jing (CNOOC Ltd, Tianjin Branch)
After more than 20 years’ development, S oilfield has entered high water cut stage. The layer contradiction is prominent and the water flooding condition is complex, which result in the complex decentralized state of the remaining oil. In order to determine the remaining oil distribution to guide the comprehensive adjustment of the oilfield, the reservoir architecture analysis of delta front was conducted.
Based on the core, seismic data, dense well logging data and production performance data, the reservoir architecture of delta front in Dongying group is characterized with hierarchy process, model guidance and numerical simulation methods. In the paper, the distribution style of interlayers in single mouth bar is discussed. The distribution feature of the remaining oil under the control of interlayers is analyzed.
It shows that multiple main channels form continuous mouth bar complex and single mouth bar develops several accretions. Interlayers in single mouth bar express in two forms: the foreset type along the source direction and the arch type perpendicular to the source direction with a low angle from 0.4° to 1.0°. Along the source direction, remaining oil gathers inside accretions whose injection-production does not correspond under the control of interlayers. And the remaining oil is enriched at the front of accretion. In the vertical source direction, the remaining oil accumulates in the high part of accretions. Under the guidance of remaining oil distribution characteristics controlled by reservoir architecture, one horizontal well was deployed. The average output is more than 100m3/d and the water cut is under 30%, which indicates the effect of this reservoir architecture analysis work.
The successful implementation of the horizontal well demonstrates the vital function of the reservoir architecture research for this kind of mature oilfield. This will also be one promising research direct for the overall adjustment and remaining oil tapping.
Yu, Hao (Southwest Petroleum University and Pennsylvania State University) | Dahi Taleghani, Arash (Pennsylvania State University) | Gonzalez Chavez, Miguel (Petroleos Mexicanos) | Lian, Zhanghua (Southwest Petroleum University)
Microseismic data and post-fracturing production have confirmed the positive role of fracture complexity on production enhancement in fractured wells. While operators are looking for different fluids and pumping schedules to enhance fracture complexity, the mechanisms ruling the process is not fully understood. This paper provides a comprehensive workflow to model the fracture pattern development by accounting for interactions with numerous natural fractures. We present a robust finite element model with adaptive insertion of three-dimensional cohesive elements for fracture propagation through the intact rock as well as the network of intersecting natural fractures. Cohesive elements are coupled with general Darcy's flow to incorporate fluid flow as well as elastic and plastic deformations of rock during initiation, propagation and closure of hydraulic fractures. Hydraulic fracturing treatment has been simulated for different natural fracture patterns. Fluid injection pressure fluctuations are observed while reopening natural fractures. The impact of operation schedules on network complexity such as hesitation time is investigated. The complexity of fracture network is characterized by the ratio of total fracture length to its effective radius from the wellbore. Our analysis has shown that in addition to the differential stress and the fracture intersection angle which are already determined by the nature, pumping injection rate and hesitation time can play a significant role in fracture branching and its diversion to different natural fracture sets. Higher injection rate is found to have a positive effect to overcome the resistance of natural fractures in different directions, and hesitation in the middle of pumping can force the fracture to divert into other directions, both of which help develop a more complex fracture pattern.