Tight Oil Reservoirs: Characterization, Modeling, and Field Development

By Hadi Belhaj

Tight Oil Reservoirs: Characterization, Modeling, and Field Development, the latest release in the Unconventional Reservoir Engineering Series, delivers a full spectrum of reservoir engineering guidelines so that the engineer can focus on every stage of development specific to tight oil. Covering characterization, micro- and nano-scale modeling, drilling horizontally, completing hydraulic fracturing, and field development, each section includes case studies, practice exercises, and future references for even deeper understanding. Rounding out with coverage on field economics and remaining challenges, this book puts control in the engineer’s hands.

In this ongoing series, each release will discuss the latest resources, explain their importance in the market, show the benefits of the resource through the latest research, provide details and protocols on how to evaluate and develop the resource, and give case studies and practice questions to gain practicality.

• Supports the petroleum engineer with a structured table of contents focused on one unconventional resource, making research and solutions easier to find
• Covers the full spectrum of reservoir engineering including modern research, development, field application, and environmental considerations
• Applies practicality with case studies, exercises, and references included in every chapter

• Language: English
• Publisher: Elsevier Science
• Release date: Jan 21, 2023
• ISBN: 9780128202708

Hadi Belhaj

Dr. Hadi A. Belhaj is a petroleum engineering faculty member at Khalifa University (KU) teaching a variety of graduate and undergraduate courses ranging from reservoir engineering to unconventional reservoir characterization and modeling to drilling engineering to petroleum economics and risk analysis to hydrogen resourcing, storage, and recovery to CCS. Dr. Belhaj has over 40 years of combined industrial and academic experience with key qualifications and research achievements in reservoir engineering, reservoir simulation, modeling fractured reservoirs, EOR, reservoir stimulation, sand production, unconventional reservoirs, and decarbonized fossil fuels. Geographically, his experience spreads over North America, Europe, North Africa, Asia, and the Middle East. Prior to KU/PI merging, Dr. Belhaj was engaged with the Petroleum Institute, Texas Tech University, and Dalhousie University, respectively. From 1982 until 2000, Dr. Belhaj worked with Schlumberger and the Libyan National Oil Corporation (LNOC), respectively. Dr. Belhaj is a Distinguished Member of the Society of Petroleum Engineers (SPE). For his unwavering 40-year-long-continued outstanding services with passion, commitment, and dedication to the SPE and its members at all levels, the SPE honoured Dr. Belhaj with the 2021 SPE Distinguished Service Award. He is also is the recipient of 2013/2020 SPE Regional Distinguished Achievement for Petroleum Engineering Faculty Award and the 2019 SPE Regional Reservoir Description and Dynamics Award. Dr. Belhaj is currently a member of the JPT Editorial Committee and SPE-ATCE Technical Program Subcommittee and has served on numerous other SPE and none SPE educational, research, and judging-related committees as well as conference, workshop, forum programming, and organizing committees. Dr. Belhaj has contributed several consortium research proposals dealing with petroleum and energy exploitation challenges generating more than 17 million dollars of research grants. He has published more than 150-refereed journal and conference articles. Dr. Belhaj is a member of other professional societies and organizations around the globe; the Society of Special Core Analysts (SCA), the International Society for Porous Media, and the OMAE-ASME are among them. Dr. Belhaj currently serves as the Associate Editor for the Springer Journal of Petroleum Exploration and Production Technology Journal and the Taylor & Francis Petroleum Science and Technology Journal. Dr. Belhaj earned a PhD from Dalhousie University, Canada, an MSc from the Technical University of Nova Scotia, Canada, and a BSc. from the University of Tripoli, Libya.

Book preview

Chapter 1: Introduction

Unconventional reservoirs represent the impending revolution in the oil and gas sector as a result of the significant expansion in global energy consumption predicted by the United States Energy Information Association Outlook (U.S. Energy Information Administration, 2012) and the increasing depletion of traditional hydrocarbon supplies. Due to the increased demand, active exploration of unconventional accumulations that were previously shelved because of production challenges is now being explored and largely produced. Unconventional reservoirs include varied geological features (Harris, 2012;), inconstant geochemical characteristics, complicated petrophysical properties, instabilities in fluid phase behavior, and a variety of controlling flow mechanisms. Unconventional reservoirs include various reservoir types such as coalbed methane, tight oil and gas, heavy oil, shale oil and gas, gas hydrates, and other types.

Due to the nature of the formation of tight reservoirs, low permeability is one of the characteristics leading to reservoir unconventionality, in consort with the low porosity and capillary pressure. Moreover, the mentioned characteristics resulted in exploration and production complexity and difficulties (Salahuddin et al., 2018). The tightness of reservoirs is the result of a confluence of factors, including the depositional environment and the diagenesis process that occurs after the depositional environment.

Tight oil is oil confined in reservoirs with low or ultra-low rock permeability, leading to poor reservoir flow efficiency. The permeability of the rock matrix is generally in the 10–1 mD range or less, while the porosity is between 1% and 10%. Some sandstone and carbonate reservoirs may have significantly poorer permeabilities for conventional development (Moridis et al., 2010). Tight sandstone gas is gas generated in sandstone and has a permeability matrix of less than 10–1 mD and a porosity threshold of less than 10%. There are no obvious traps or direct caprocks, although regional seals are well-formed (Zou et al., 2013). Because of the reservoir's unconventionality as a consequence of the weakly permeable medium, it was evident that a better solution was critical to understanding the behavior of fluid flow, the flow regime, and forces/mechanisms governing such medium. Diffusion, viscous, convection, desorption, inertial, capillary, sorption, and viscoelastic forces are present in unconventional reservoirs and influence fluid flow. Based on their regulating impact, these mechanisms are divided into two groups: trapability and displacement (Belhaj et al., 2019). Trapability forces contribute to the trapping of the wetting phase fluid, while displacement governs fluid movement across the porous medium at the nano-, micro-, and macrodimensions. The flow in porous media is influenced by several physical processes and mechanisms depending on the reservoir type and conditions, as well as the forces operating as trapability or displacement, where the influence of some forces dominates more than other forces (Belhaj et al., 2019). As a result, the existing technique of calculating pressure drop and flow concentration equation—Darcy’s—is inadequate owing to its lack of precision and validity due to ignoring the majority of the controlling factors. Furthermore, understanding the unconventional reservoir will assist in creating a novel and economically viable model for unconventional well development that takes into consideration the desorption effect along with diffusion.

This book comes at a very critical time where the future of fossil fuel and other energy resources at large is at stake. The need for smart technologies to produce cheap oil and gas while eliminating or substantially reducing the negative environmental impacts is a must for the petroleum industry to continue leading the worldwide energy resources. The author believes that producing oil and gas will remain for quite a long time, and the need for increasing the recovery factor from unconventional oil resources will be the only resort after depleting most of the conventional plays. This will attract more investors to these types of reservoirs and hence expand exploration, drilling, production, and R&D support. We require very strict industrial practices and regulations to ensure safe and environmentally friendly operations. The zero-emission policy must be a prime target. Hydrogen energy is believed to be the world's future energy resource. There is also a great chance to resource hydrogen from fossil fuels like hydrocarbon gases, coal, and even crude oil. This comes with the challenges of utilizing the effluent carbon (e.g., construction material) and establishing efficient CO2 capture and sequestration (CCS) programs. The near future will carry more good news for the energy sector through the discovery of naturally trapped hydrogen in geological subsurface strata and produce it in the same manner as natural gas reservoirs. This will pave the road for a perfectly clean White energy resource.

References

Belhaj H.A., Qaddoura R., Ghosh B., Saqer R. Modeling fluid flow in tight unconventional reservoirs: nano scale mobility/trapability mechanistic approach!. In: SPE-198676-MS, SPE Gas & Oil Technology Showcase and Conference, Dubai, UAE, 21–23 October; 2019. https://doiorg.libconnect.ku.ac.ae/10.2118/198676-MS.

Harris C. What Is Unconventional Resources? Long Beach, CA, USA: AAPG Annual Convention and Exhibition; 2012.

Moridis G.J., Blasingame T.A., Freeman C.M. Analysis of mechanisms of flow in fractured tight-gas and shale-gas reservoirs. In: Proceedings of the SPE Latin American and Caribbean Petroleum Engineering Conference; Lima, Peru: Society of Petroleum Engineers; December 2010:1–3.

Salahuddin A.A., Seiari A., Jamila M., Shehhi A., Abdulla S., Khaled E., Hammadi A. Tight reservoir: characterization, modeling, and development feasibility. In: Paper presented at the Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE; November 2018:doi:10.2118/192778-MS.

U.S. Energy Information Administration. EIA—Independent Statistics and Analysis. Short-Term Energy Outlook—U.S. Energy Information Administration (EIA); 2012. Available from: https://www.eia.gov/outlooks/steo/.

Zou C.N., Yang Z., Tao S.Z., Yuan X.J., Zhu R.K., Hou L.H., Wu S.T., Sun L., Zhang G.S., Bai B. Continuous hydrocarbon accumulation over a large area as a distinguishing characteristic of unconventional petroleum: the Ordos Basin, North-Central China. Earth-Sci. Rev. 2013;126:358–369.

Chapter 2: Classification of unconventional reservoirs

Summary

Classification, in general, is beneficial only when the classified matter has a clearly known system. In unconventional reservoirs, this is not the case! Hence, classifications of these kinds of reservoirs are different based on the purpose of the classification and the background of the classifier. Different criteria for the classification of unconventional reservoirs have been developed for different objectives using the geology and environment of deposition of the reservoir, petrophysical characteristics, complexity, and hydrocarbon produced. This chapter discusses some of these classifications and adopts the one that serves the purpose of this book, i.e., that best suits the characterization and modeling of tight unconventional reservoirs. The source of unconventionality for such reservoirs lies in the rock properties, specifically the permeability. Based on this criterion, reservoirs with rock permeability less than 0.0001 mD are considered extremely tight, and those with a permeability range of 0.0001–0.001 mD are considered very tight. A permeability range of 0.001–0.01 is considered tight permeability, a permeability range of 0.01–1.0 mD is considered low permeability, a permeability range of 1.0–10 mD is considered moderate permeability, and a permeability range of 10–100 mD is considered high permeability. Hence, the clear tight unconventional reservoirs are those characterized by permeability of less than 0.01 mD, while clear conventional reservoirs are characterized by a permeability value higher than 1.0 mD, according to these criteria. The reservoirs that have a permeability range between 0.01 and 1.0 mD can be low-permeability conventional, or tight unconventional reservoirs. It is worth mentioning that the permeability of the reservoir is extremely important for modeling as it describes the macro-, micro-, or nanoscale mechanisms’ contributions to fluid flow.

Keywords

Unconventional reservoirs; Classification of UCRs; Tight shale; Tight source rock; Low permeability; Micro-/nanoscale

UCRs are just like people! No matter how you classify them, each one remains unique!

2.1: Reservoir classification strategy

Unconventional reservoirs (UCRs) have received significant interest in recent years and have become a major supplier to the oil and gas market. Increasing demand for energy has now forced the oil industry to consider unconventional resources more seriously. Academic research and industrial-based R&D efforts for the last two decades have made significant progress on the commercial development of unconventional resources encouraged by increased oil prices during this time span. Rapid technological advancement with respect to horizontal drilling and hydraulic fracturing contributed significantly to the development of such energy resources. However, a thorough understanding of the complexity of unconventional reservoirs and generating affordable and efficient technologies to develop them are still way beyond the petroleum industry's expectations. The gas recovery from unconventional reservoirs is still lagging behind the desired level of production. It is no secret that unconventional reservoirs hold massive energy resources that could suffice future energy consumption for hundreds of years to come. Unfortunately, the recovery factor from these reservoirs is less than 10%. This is because technologies to develop and produce these resources are shadowed a by lack of understanding of the formation and development of these reservoirs. Up-to-date characterization and modeling of UCRs are one of the most difficult tasks to achieve due to the complex nature of micro- and nanopore formation and anomalous fluid flow behavior. In many cases, the recovery factor from unconventional reservoirs is as low as 3% to 7% of the oil initially in place (OIIP). The permeability of some unconventional strata is in the range of the nano-Darcy scale. Properties like permeability, total organic content, thermal maturity, and absorbing capacity of gas onto organic materials are among the many controlling factors of the storage capacity and flow potential of unconventional reservoirs.

Unconventional reservoirs can be defined as reservoirs with distinguishable geological characteristics, variable geochemical characteristics, complex petrophysical properties, challenges in well completion, fluid phase behavior, and flow mechanism oddities. The characterization of conventional reservoirs itself is still very difficult to achieve with reasonable satisfaction despite the many years of technological development and the accumulation of experience in this area in the form of many discoveries over recent years. In addition to those conventional reservoir challenges, characterization and modeling of unconventional reservoirs is an even a bigger hurdle and poses many difficulties due to a lack of understanding of geology and rock/fluid interactions in these reservoirs. Many important parameters are hard to determine, and some of them are still unknown. Conventional rock and fluid characterization quantifying the constitutive reservoir relationships is a priority. To characterize and model unconventional reservoirs, which is crucial for their development, it is very important to address fluid flow behavior through the nanopores of tight formations. Traditional methodologies and tools used to characterize, model, and develop unconventional reservoirs can no longer be used to achieve the purpose and expectation of unconventional reservoirs. Unlike with conventional reservoirs, the modeling of unconventional reservoirs should consider not only the simple viscous forces term articulated in Darcy's law, but also many other important forces including viscoelastic, capillary, inertia, advection, convection, sorption, and desorption forces, which influence fluid flow through the nanopores of tight unconventional formations. Fully grasping and incorporating the effects of these mechanisms to fluid flow through unconventional reservoirs is a must. Building a comprehensive model to predict fluid flow through these tight formations incorporating macro-, micro-, and nanoporous scales is crucial and fundamental to modeling the fluid flow behavior in unconventional reservoirs. After building a basic model for each mechanism and assessing its effect on flow characteristics, it becomes possible to combine these basic models into a comprehensive one that combines the influences of these forces on fluid flow behavior within tight porous media. It is also important to validate these sought models’ predictions through a parametric study and define the critical parameters and their relative sensitivities. Variations of reservoir conditions including temperature, pressure, rock, and fluid properties would show the influences of these parameters on fluid flow behavior. Such models, once established, would have a big impact on developing unconventional reservoirs and hence lower their production capital and operating costs.

The first task to undertake is establishing a matrix to differentiate between conventional and unconventional reservoirs and then emphasize the classification of unconventional reservoirs. Classification of unconventional reservoirs can be different depending on the purpose of the classification, or the perspective of the classifier. Classifiers may choose their criteria based on the resource's geology and environment, quality and characteristics, complexity and difficulty of development, quality of the hydrocarbon produced, etc. This chapter reviews some of the interesting classifications and focuses on the classification adopted for the characterization and modeling of such types of reservoirs.

Classification of petroleum reservoirs has never been unique and definite throughout the history of the petroleum industry. Classifiers are always biased to their background, purpose, and style of thinking when trying to classify petroleum reservoirs. Petroleum reservoirs are, generally, classified into two categories: conventional and unconventional. Conventional petroleum reservoirs, traditionally, represent the entire history of the petroleum industry. Although unconventional reservoirs have been discovered, they have never been developed for the complications of their rock and/or fluid properties that make their capital and operational cost a big concern until recent years. On the one hand, many of the conventional reservoirs have been put in production for many decades, while many others have already been abandoned. The knowledge and methods required to develop these types of reservoirs are generally established. That is not to say everything is known; a mere 25% global recovery factor of many of them suggests otherwise. Producing the remaining 75% is still an area of active research. Alternatively, unconventional reservoirs are still in their infancy stage, and serious production from some of these reservoirs is less than two decades old. Although two decades may seem like a long time, the global recovery factor from unconventional reservoirs is almost negligible. Those developed among them have less than a 10% recovery factor. Unlocking the trapped oil and gas in these reservoirs with affordable technology is a major industrial challenge and serious R&D topic.

Unconventional reservoirs revolutionized the way we think of conventional reservoirs. Many of the innovative ideas and breakthroughs initially intended for unconventional reservoirs made their way to applications in conventional reservoirs. Horizontal well staged fracturing and 3D seismic are just examples of the innovations that fueled the unconventional hydrocarbon boom in North America and made their way to conventional reservoirs. This migration of technology resulted in improved recoveries, reduced costs, or both. Likewise, many of the developed theoretical concepts had influenced and changed our perception of conventional reservoirs. These could include the coexistence of conventional and unconventional reservoirs, the distribution of oil and gas accumulation, migration of hydrocarbons, and hydrocarbon trap theory, to name a few. The latter was formally introduced in 1934 by McCollough (McCollough, 1934). As a result, our idea of what constitutes a petroleum trap has been forever changed.

Strategies for identifying and evaluating unconventional reservoirs are considerably different from those of conventional reservoirs. In unconventional reservoirs, the goal is to recognize continuous or semicontinuous accumulations and then identify hydrocarbon enrichment spots (conventionally, known as sweet spots) that would be economically feasible to produce under the current market conditions. On the other hand, conventional reservoirs are identified by recognizing a trap that accounts for a hydrocarbon accumulation. This accumulation is then evaluated and developed for hydrocarbon production potential with an objective of preferably high and stable production for quite a long period of time.

2.2: Classification of petroleum systems

Before the classification question of conventional and unconventional reservoirs is addressed, it is only appropriate to address why petroleum systems are classified into conventional and unconventional reservoirs. Traditionally, shallow wells were drilled and hydrocarbons would flow through them naturally to the surface. Over the years, slow, but steady technological improvements were made to access more complex and challenging reservoirs, but the fundamental approach to drilling and completion did not change much. However, in the early 1990s, George Mitchell was the first to develop a technique that combines horizontal drilling with hydraulic fracturing. This is how hydraulic fracturing in its modern sense started. This revolutionary technique represented a leapfrog in technology that signaled the birth of the shale oil boom. Vast unconventional accumulations that were considered uneconomic in the past suddenly became major sources of oil and gas and a very important element of the energy supply equation. The result was an increase in oil production by over 10 million barrels per day over the following three decades in the United States alone. In addition, a new term was coined for these types of accumulations, unconventional reservoirs (UCRs). The unconventional reservoirs do not only require entirely new development strategies but also pose very different petrophysical and fluid properties along with non-Darcy flow characteristics. Nowadays, many scientists even question the applicability of the fundamental laws of fluid flow in porous media to these reservoirs. Given the many differences between these two types of reservoirs, a new research body has developed all around the world, and the need for a new and appropriate way to classify these reservoirs became apparent.

2.2.1: Classification of conventional petroleum reservoirs

Conventional petroleum reservoirs can be broadly classified as oil and gas reservoirs. These broad classifications can be further classified depending on several criteria: fluid composition, initial reservoir pressure and temperature, and pressure and temperature of the surface production. These are usually governed by phase diagrams; however, the discussion of conventional phase diagrams (in many cases referred to as pressure/volume/temperature—PVT analysis) is not within the scope of this book.

Initial reservoir pressure is of central importance in further classifying conventional oil reservoirs. If the initial reservoir pressure is above the bubble-point pressure, then the reservoir is classified as an undersaturated oil reservoir, while reservoirs with initial pressure equal to the bubble-point pressure are classified as saturated oil reservoirs. In case the initial reservoir pressure is below the reservoir pressure, then it would be classified as saturated with gas-cap reservoir. Moreover, oil reservoirs can be classified based on crude oil quality and properties into black oil, low-shrinkage oil, volatile oil, and near-critical crude oil.

Unlike with oil reservoirs, initial reservoir temperature plays a central role in classifying gas reservoirs. In this respect, the four most important subclassifications are discussed here. The first type is the retrograde gas-condensate gas reservoir. This reservoir has a temperature between the critical temperature and cricondentherm of a reservoir fluid. The second type is the near-critical gas-condensate reservoirs. As the name suggests, this type of subclass of reservoirs is reserved for reservoirs with a temperature near the critical temperature. The third type is the wet-gas reservoirs. Most gas accumulations fall into this category. It includes gas reservoirs with a temperature above the cricondentherm of the hydrocarbon mixture. In this type of gas reservoir, very light hydrocarbon liquid condenses out of the gas in the reservoir and through the production stream as temperature drops from the reservoir to the surface conditions. The fourth type is dry-gas reservoirs. In this case, the hydrocarbon gas stays in a single phase in the reservoir, and during production, it is only to be accompanied by some water, as is the case with all oil and gas production.

There exist many other classifications of conventional hydrocarbon reservoirs. Here, the discussion will be restricted to two important classifications, on the basis of storage and flow characteristics of the reservoir and on the basis of reservoir geometry.

2.2.1.1: Classification on the basis of storage and flow characteristics of the reservoir

Storage and flow characteristics are governed by hydrocarbon storage domain and dominant flow channels. The first is the porous reservoirs; these are the type of reservoirs that relate most to a porous medium. In this case, intergranular pores are the main storage domain. Typically, these would be sandstone, conglomerate, bioclastic limestone, and oolitic limestone reservoirs. The second is the fracture porosity reservoirs, where natural fractures are the main flow domain, while the porous matrix is the main storage domain. They are also referred to as dual-porosity single-permeability reservoirs. The permeability of these reservoirs is usually low, but the fractures reach long distances. Examples of these types of reservoirs include the Spraberry Trend oil field in the United States and the Renqiu carbonatite oil field in China. The third type is fractured reservoirs, where the natural fractures are not only the main flow domain but also the main storage domain. The pores in these reservoirs are either nonexistent or disconnected. Typically, these reservoirs would be tight carbonatite, metamorphic rock, and mud shale gas reservoirs. The fourth type is fracture porosity reservoirs. In these reservoirs, the hydrocarbons are stored in both the fracture and matrix domains (these reservoirs are also referred to as dual-porosity dual-permeability reservoirs). In addition, the fractures only reach short distances. The fifth type is combined fracture-vuggy-pore reservoirs, where the fracture and matrix domains, as well as the vugs, contribute to the storage capacity and flow potential of hydrocarbons (these reservoirs are also referred to as triple-porosity reservoirs).

2.2.1.2: Classification on the basis of reservoir geometry

In this type of classification, reservoirs are categorized based on their geometry. They are divided into massive, stratified, fault block, and lenticular reservoirs in accordance with the geometry.

The first type is massive reservoirs; these could be oil or gas reservoirs. The most important feature is the high effective thickness (more than 32 ft). The second is stratified reservoirs, and these are typically anticline traps with complete structure and well-established oil-water interface. The reservoir would be stratified into smaller strata and varying permeabilities. The Daqing reservoir in China is one of the prominent examples of this type of reservoir. The third type is fault block reservoirs, where major faults subdivide the reservoir into fault blocks of varying sizes. These reservoirs are also stratified. Some of the faults may be sealing resulting in various oil-water contacts and even different initial reservoir pressures. The fourth is lenticular reservoirs, and this type refers to the overlapping body of sand lenses. Lenses are defined as sand bodies with a length-to-width ratio equal to or less than