|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Introduction Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs. Tight gas reservoirs have one thing in common--a vertical well drilled and completed in the tight gas reservoir must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Normally, a large hydraulic fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells and/or multilateral wells can be ...
Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs. Tight gas reservoirs have one thing in common--a vertical well drilled and completed in the tight gas reservoir must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Normally, a large hydraulic fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells and/or multilateral wells can be used to provide the stimulation required for commerciality.
Temizel, Cenk (Saudi Aramco) | Canbaz, Celal Hakan (Ege University) | Gok, Ihsan Murat (NESR) | Roshankhah, Shahrzad (California Institute of Technology) | Palabiyik, Yildiray (Istanbul Technical University) | Deniz-Paker, Melek (Independent Consultant) | Hosgor, Fatma Bahar (Petroleum Software LLC) | Ozyurtkan, Mustafa Hakan (Istanbul Technical University) | Aksahan, Firat (Ege University) | Gormez, Ender (Middle East Technical University)
As major oil and gas companies have been investing in shale oil and gas resources, even though has been part of the oil and gas industry for long time, shale oil and gas has gained its popularity back with increasing oil prices. Oil and gas industry has adapted to the low-cost operations and has started investing in and utilizing the shale oil sources significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of shale oil and gas reservoirs as a significant source of energy in the current supply and demand dynamics of oil and gas resources. A comprehensive literature review focusing on the recent developments and findings in the shale oil and gas resources along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research using SCOPUS database to other renowned resources including journals and other publications. All gathered information and data are summarized.Not only the facts and information are outlined for the individual type of energy resource but also the relationship between shale oil/gas and other unconventional resources are discussed from a perspective of their roles either as a competing or a complementary source in the industry. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the shale oil/gas as it stands with respect to other energy resources. Among the few existing studies that shed light on the current status of the oil and gas industry facing the rise of the shale oil are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between heavy and light oil as a complementary and a competitor but harder-to-recover form of hydrocarbon energy within the era of rise of renewables and other unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals. 2 SPE-198994-MS
There is a very extensive amount of information and learnings from naturally fractured reservoirs (NFRs) around the world collected throughout several decades. This paper demonstrates how the information and learnings can be linked with tight and shale reservoirs (TSRs) with the objective of maximizing hydrocarbon recovery from TSRs.
A classic definition indicates that a natural fracture is a macroscopic planar discontinuity that results from stresses that exceed the rupture strength of the rock (
Actual observations in TSRs indicate that micro and nano natural fractures do not flow significant volumes of oil or gas toward horizontal wells. Thus, the wells must be hydraulically fractured in multiple stages to achieve commercial production. Once the wells are hydraulically fractured, the area exposed to the shale reservoir is enlarged and the natural micro and nano fractures flow hydrocarbons toward the hydraulic fracture, which in turn based on the values of hydraulic fracture permeability, feeds those hydrocarbons to the wellbore. In TSRs there are also completely cemented macroscopic fractures that are breakable by hydraulic fracturing and can become very effective conduits of hydrocarbons toward the wellbore.
The link that exists between natural fractures at significantly different scales established in this paper is a valuable observation. This is so because the larger tectonic, regional and contractional (diagenetic) fractures that exist in NFRs have been studied extensively for several decades, for example in carbonates, sandstones, and basement rocks. Those learnings from NFRs have not been used to full potential in TSRs for maximizing oil and gas recoveries. This paper provides the necessary tools for remediating that situation.
The established link between NFRs and TSRs permits determining how to drill and complete wells in TSRs. It is concluded that this link will lead to (1) improvements in gas production performance, and (2) maximizing economic oil rates and recoveries under primary, improved oil recovery (IOR) and enhanced oil recovery (EOR) production schemes.
The Vaca Muerta (VM) formation, one of the largest unconventional reservoirs worldwide located in the Neuquén basin, has ceased to be a promise and is becoming a venturous reality. During recent years, the investments in its development have increased significantly. By the year 2040, it is believed that the VM formation may generate 560,000 bbl of liquid and 6,000 million cubic feet of gas per day.
One of the primary challenges of many operators has been to select the most productive landing zones; consequently, the performance of an accurate and complete petrophysical evaluation of the reservoir has become vitally important to increase production and to optimize well completion costs. The evaluation of shale formations using electrical logs is a major challenge for most petrophysicists because many of the measurements from the logging tool are affected by the organic matter concentrated in this type of rock.
This paper highlights the way in which these challenges were addressed. It describes the logging operation, as well as the integral petrophysical interpretation performed for a pilot well located in the oil window of the VM formation.
The key element for the success of this work was the implementation of the integrated workflow to evaluate the potential of the shale oil well. The integrated workflow enabled the identification of hydrocarbon-bearing formations, quantification of reservoir properties and hydrocarbons in place, determination of lithology variations within the objective section, and establishment of reliable correlations between electrical logs and the organic richness of the VM formation. In addition, the assessment of geomechanical properties has become vitally important to optimize well placement and to select the best hydraulic fracturing design.
The integrated analysis of the pilot well presented in this paper has proven to be a successful case in which an effective characterization of the VM formation, following the proposed formation evaluation workflow, and the integration of wireline data with the various data acquisition program components, enabled the delivery of recommendations about the prospective interval in which to land the programmed lateral well.
Improvements in drilling and completion technology have resulted in significant increases in production rates from new horizontal wells in the United States. Observations over many years show that a well’s initial rate often has a predictable relationship to decline trends indicating a rate related bias in decline trends. This paper studies the relationship between initial flow rates and related decline trends and reserves forecasts for many of the major horizontal development plays in the United States and confirms that there is a rate related bias. Early decline trend forecast methods considering rate bias lead to improved reserve estimates and fewer revisions to estimates as wells mature. The study does not provide a methodology for determining peak rates but focuses on bias in decline trends related to known peak rates.
For years, reviews of oil and gas reserves estimates have shown that downward revisions on high rate wells (Lee 2017, Lee 2019) have been more common than upward revisions indicating a rate related bias. Various authors have discussed methods to correct various biases (SPEE 2010, 2016) (Freeborn 2012, 2013) which tend to result in overestimating production forecasts. Our experience is that forecast bias to the high side is more significant for high rate wells than for low rate wells. This rate Figure 1. Twelve areas for which peak month rate to decline trends relationships are presented. dependency raises the question of whether a rate dependent bias can be documented and corrected. This paper focuses on one factor: the relationship between peak month rates and decline trends or rate dependent decline trend bias. Results are presented for twelve areas noted in Figure 1 with an attempt to minimize rate dependent estimation bias.
High rate bias was documented with production data from a group of similar wells which was sorted from high peak rate to low peak rate and binned for analysis. This ranking minimizes time sequence bias which results when the best wells are drilled first with poorer wells later or if the better wells are drilled toward the end of a study period. The peak rate ranked wells are divided into approximately equal bins with each bin analyzed to determine the expected decline trends for the bin. The decline trends of the bins are then compared to the bin’s peak month rate to document the relationship between decline trends and peak rates.
Over the past twenty-five years, more than 3,500 wells have been drilled in the giant Pinedale Field in the northern Green River Basin of Wyoming, at spacing intervals as tight as 5-acres and completed in the 6,000 ft. reservoir column of stacked, tight-gas, fluvial sandstones. Even with this high density of well control, geologic uncertainties remain regarding the geometry and architecture of the highly heterogeneous fluviatile basin-fill. The goal of this project was to predict the distribution and size of the reservoir facies using geocellular-modeling techniques.
A process-based depositional framework formed the starting point for our characterization study. Examples from modern analogs and the rock record were used to condition the model inputs as related to channel size, scaling relationships (including net/gross), and overall reservoir architecture; the fluvial depositional sequences comprise a distributary fluvial system. At a range of scales, a seismic inversion facies volume, supplemented with a dense population of well logs, and core data helped constrain the size, geometry and distribution of reservoir facies at multiple, geologically distinct intervals. The resulting geocellular model honors all input data. Vertical upscaling is primarily constrained by well logs and core. Lateral facies distributions are primarily constrained by the seismic inversion column paired with well data.
By combining sedimentologic interpretations from seismic and well logs, this integrated study was able to differentiate fluvial reservoir sandstones from overbank siltstones and mudstones. This technology-driven reservoir characterization study was undertaken to improve our understanding of resource-in-place and to optimize wellbore placement and construction, for ongoing field development.
Pinedale Field is defined largely by the Pinedale Anticline in the northern part of the Green River Basin in Sublette County, Wyoming and is approximately 35 miles long with a NNW trend (
Askarova, Aysylu (Skolkovo Institute of Science and Technology) | Turakhanov, Aman (Skolkovo Institute of Science and Technology) | Mukhina, Elena (Skolkovo Institute of Science and Technology) | Cheremisin, Alexander (Skolkovo Institute of Science and Technology) | Cheremisin, Alexey (Skolkovo Institute of Science and Technology)
The present study is devoted to the simulation of thermal enhanced oil recovery (EOR) method with a focus on the initial distribution of various organic matter (OM) groups. Several important aspects of modeling methodology are studied to build a robust simulation strategy such as the number of pseudo-components introduced to the model, kinetic reactions, viscosities, and relative permeability curves. The purpose of this study is to develop a complex approach including experimental and numerical simulation for the investigation of complex processes taking place during thermal EOR application in a target unconventional reservoir sector.
The research is divided into two parts: the first part is the experimental investigation and the second is the numerical simulation. The laboratory experiments are focused on a specification of distribution of OM groups using core samples and experiment in an autoclave, where hot water was injected at reservoir pressure and 350°C temperature. Sequential reaction mechanism, where solid, immobile pseudo-components as kerogen and bitumen crack to heavy oil, light oil, hydrocarbon gas, and coke, was used to match the produced hydrocarbons. The numerical simulation consequently recreated the autoclave experiment. Various kinetic models were tested with different types of pseudo-components and compared with experimental results.
"History matched" kinetic model describes the kerogen and bitumen transformation with the production of liquid and gas hydrocarbons and gives a satisfactory agreement. The described kinetic model is consequently implemented to demonstrate an influence of the specification of initial matrix saturation with OM and its further transformations. Addition of bitumen fluidity greatly affects the dynamics of cumulative oil production and the prediction of thermal EOR efficiency.
This paper describes the importance of the chemical model and level of the detailed description of pseudo-components in thermal EOR modeling considering the features of the unconventional reservoirs. It is of prime importance to better understand the physics of the displacement processes and identify potential means to improve oil recovery from unconventional reservoirs. The developed simulation improvement approach is proposed to clarify the nature of thermal EOR.
Production underperformance of a historical infill (child) lateral well was confirmed by observation and modeling to be due to offset vertical well interference. These results led to utilizing a seismic-driven earth model, three-dimensional hydraulic fracture, and reservoir models for a planned horizontal well. The goal was to apply past learnings to maximize completion potential and understand the economic viability of infill horizontal well development in the Greater Green River Basin. The results of this study provided insight to determine future horizontal development strategy.
In-situ model input parameters along with field-scale structure were informed by 3D seismic and vertical log data. Parameters were further calibrated to core and offset well DFIT’s with subsequent treatment history matching validation. Modeled fracture geometries were incorporated into a reservoir simulator to history match parent well production. This exercise provided an accurate representation of pressure depletion and stress profiles around the planned horizontal child well. Additionally, this provided a platform to investigate potential completion strategies, landing zones, and a subsequent production assessment based on uncertainty analysis to determine economic potential.
Targeting a deeper landing location compared to the previously drilled horizontal well resulted in reduced expected interaction with offset wells. Hydraulic fracture design sensitivities indicated child well frac hits and asymmetrical fracture growth can be mitigated or lessened with increased intra-stage cluster count and efficiency to prevent "super frac" generation.
An assessment based on fracture model sensitivity results were coupled with reservoir uncertainties to forecast production. Simulation indicated that the most significant impact on production was a result of porosity, saturation, and permeability assumptions. Two separate models were developed, one based on log derived properties and the other being inferred from core properties and assigned to facies from Gamma Ray. The objective of the stimulation was to maximize hydraulic fracture flowing area with fluvial sand bodies while minimizing cost. Increased sand loading was thought to be the primary driver. The simulation showed that increasing sand loading from 1000 lb/ft to 1500 lb/ft only generated an incremental 0.2 Bcf indicating the lower amount of sand is the economical choice. Capital savings were generated by increasing the stage length while maintaining cluster efficiency reducing stage count by 5. However, even with the capital savings, forecasted production scenarios averaged around 7.15 Bcf missing their economic breakeven. As a result of this work, the decision was made not to drill the well and instead explore alternative prospects for horizontal development.
Gaddipati, M. (NITEC LLC) | Firincioglu, T. (NITEC LLC) | LaBarre, E. (ULTRA Petroleum) | Yang, Y. (ULTRA Petroleum) | Wahl, D. (ULTRA Petroleum) | Clarke, P. (ULTRA Petroleum) | Long, A. (ULTRA Petroleum) | Ozgen, C. (NITEC LLC)
In recent years multi-stage fractured horizontal wells have become a norm in the development of unconventional oil and gas reservoirs. This paper focuses on reservoir modeling of the tight-gas sandstones in Pinedale Field, Green River Basin, Wyoming. This paper represents the first published literature to focus specifically on horizontal well performance in Pinedale. The objective of this study was to evaluate horizontal well productivity of the hydraulically fractured Lance Pool formation. Due to the fluvial nature of the formation and the complexity introduced by the hydraulic fracturing, an integrated workflow was developed utilizing a 3D simulation model combining seismic reflection, inversion, petrophysical and geological data.
A 3D facies model based on object-oriented geostatistical modeling was constructed using a combination of vertical lithology proportion curves (from vertical pilot wells) and reservoir net-to-gross (NTG) maps extracted from a deterministic seismic inversion volume. The NTG maps were honored during the geostatistical population of the fluvial sand bodies (sand generation model). The resultant facies model was then populated with petrophysical and geomechanical properties using the interpreted well logs. The final integrated model honors published characteristics for the Lance Formation. A dual-porosity reservoir simulation model was then utilized. The reservoir simulator integrated the hydraulic fracturing process, multi-phase flow and geomechanics in order to assess SRV generation during hydraulic fracturing and SRV geometry changes during production. The change in mean stress for each grid cell was implicitly solved with pressure and the other flow variables using poro-elastic information. The simulation model was calibrated to history match flow back and depletion periods including historical gas, oil (condensate) and water production rates together with the bottom hole pressure values.
A physics-based history matched simulation model was generated, including flow behavior for two wells in the study area. The hydraulic fractures created/propagated for sandstone and siltstone were tuned as history matching parameters. The calibrated model showed that major pressure depletion is limited to the sand channels due to ductility contrasts with the finer-grained facies. Predictive cases were modeled for 30- year EUR. The study refined our understanding of well performance drivers as related to advanced reservoir characterization, affording a robust prediction tool for undrilled locations.
The integrated reservoir modeling technology presented in this study is impactful as it solves for geomechanics and flow in a single process. The multi-well calibration of the model provides physics-based assessments of gas production from a complex reservoir, leveraging horizontal well technology. Predictive cases illustrate a quantitative performance characterization tool for decision making, including field optimization and development.
To include the all the complexities associated with the reservoir coupled with hydraulic fracturing of horizontal wells, this study required a thorough integration of different disciplines from geology, petrophysics, geophysics, geomechanics and engineering in building a 3D reservoir simulation model. All the available data from different disciplines was analyzed and integrated to a create a consistent physics-based model.