The Importance Of Image Based Technology In Petroleum Engineering

Based off of MICP data collected from core (Figure 19), the Pronghorn siltstone has a permeability on par with the upper and lower Bakken shales. The lack of permeability is supported by lithological analysis indicating a clay content of up to 50 % (Figure 20) across the Painted Woods asset. The low permeability and high clay content shows that the Pronghorn does have the potential to occlude primary migration of hydrocarbons from the lower Bakken shale into the underlying upper Three Forks. However, this only has a minimal effect on the overall potential of the upper Three Forks as a whole.

The Eagle Ford shale formation in south Texas has recently become the focus of many oil industry operators searching for new sources of hydrocarbons by using the latest technology in previously unexplored areas. This exploration enhances the development of even more advanced techniques as issues are identified and problems solved to address the unique properties of the formation and the surrounding surface environment. Even though a formation may be comprised of a single sedimentary layer from a similar geological time frame it is not a homogeneous block and has many features and anomalies that effect the pressure, permeability, type of hydrocarbons trapped and methods required to extract them. To understand these properties one must understand that shale is a fine-grained sedimentary rock that forms from the compaction of silt and clay placing it in the mudstone category of rocks [1]. Shale is different from other rocks in this category because it has a fissile structure and is laminated. The black shale in the Eagle Ford formation (Fig 1.) has a special property such that it contained organic material when it was deposited and during compaction over a millennium, the organic materials were converted into trapped oil and gas hydrocarbon deposits. This oil and gas are very difficult to remove because it is trapped within tiny pore spaces and or adsorbed onto clay mineral particles that makeup the shale.

The main purpose of this lab was to study the capillary pressure (Pc) in eight sandstone core samples in order to obtain saturation values and the height above the free water contact in the reservoir rocks. In general, capillary pressure can be defined as the difference in pressure between two immiscible fluid phases (usually oil and water) that occupy the same pores. It is basically generated by the interfacial tension between two different phases. It is considered to be one of the important factors that control fluid distribution in reservoir rocks. Moreover, capillary pressure can be the key to determine the relationship between important rock properties such as porosity, permeability, and water saturation above oil-water contact in reservoirs.

Seismic imaging is the process of synthesizing the wealth of subsurface information available from reflection seismic experiments by recording ambient sound with an array of geophones distributed at the surface. It is a tool that bounces sound waves off underground rock structures to reveal possible crude oil and natural gas. The geophones are used to record the sound waves where they echo within the earth. Petroleum geologists seek to calculate the depth and structures of buried geologic formations based on these echoes. It helps them identify oil and gas bearing reservoirs hidden beneath the earth's surface. Chevron used their modeling and analytics to exploit deep water drilling and hydrocarbon extraction in areas with challenging geographies (Artman, 2005).

Brereton et al. (1998) investigated the rock properties through boreholes and surface seismic in the area of the PRZ. This allowed for comparison and correlation of overall rock porosity and permeability between the different rock units. Results indicate that in the case of the Calder and St. Bees sandstones, hydraulic conductivity and rock porosity decrease with depth (Brereton et al. 1998). More recent research by Streetly et al. (2006) into the hydrogeological characteristics below the PRZ has provided a higher resolution model of

Under the guidance of Dr. Zenon Medina-Cetina, director of SGL, I did an extensive literature review and wrote a primary honors thesis on the geologic assessment of different drilling, completion, and stimulation methods in selected gas shale plays worldwide. This research experience made me realize a multi-disciplinary approach to different problems faced by the gas shale industry, and helped me broaden my knowledge of quantitative seismology applications in the gas shale industry.

Since the purpose of hydraulic fracturing is to create secondary fractures in addition to naturally occurring within the subsurface, there is a general concern that this process might extend fractures to link aquifers. The chances of this occurring are likely remote, since the vertical distance separating the Marcellus Shale from most aquifers is usually much greater than the length of the fractures induced during hydraulic fracturing. In addition, several thousands of feet of rock layers typically overlie the Marcellus Shale and form a cap to restrict flow. It should be noted, however that if the shallow portions of the Marcellus Shale are developed, then the thickness of the overlying rocks would be less and the distance from the Marcellus to drinking water aquifers would be shorter, posing more of a risk to groundwater (DOE, 2009).

Contrary to popular belief’s Hydraulic Fracturing is not a drilling process .It is the series of steps that are used after the drilling of hole in the ground is completed to create or restore small fractures or opening in the reservoir rock formation .These small fractures or opening in the reservoir are mainly used to extract –petroleum, natural gas ( such as shale gas , tight gas , and coal seam) ,water And natural substances

2004). To interpret seismic data in terms of hydrate content, a relationship between hydrate saturation in the pore space of sediments and elastic velocity is necessary. Lee et al. (1996) developed a weighted equation model, in which hydrate is considered as a part of the pore fluid. However, this model is not based on physical principles and requires empirical calibration. The velocities predicted from the cementation theory proposed by Dvorkin and Nur (1996) are much higher than those normally observed in nature (Ecker et al. 1998). In 1999, Helgerud et al., introduced an effective

Hydraulic Fracturing is a controversial method by which we are able to obtain natural gas from subterranean natural reservoirs within the earth. This process requires a shaft to be drilled vertically below the ground, and once a target depth has been reached below fresh water aquifers, horizontal drilling can occur. A long this horizontal shaft, the wellbore, a high pressurized mixture of water, chemicals, and sand is injected in order to create fractures in the oil and gas reservoirs within the rock. When the pump pressure is relieved, sand particles are left behind which keep the fractures open, providing an outlet for the natural gas to be collected. This process can produce oil or natural gas for twenty to forty years or more

Caprock integrity failure can cause leakage and containment incidents. Currently, there are more than 400 underground storage sites in the United States, including natural gas storage, oil and gas waste disposal, industrial hazardous and non-hazardous waste disposal, and municipal sanitation waste disposal. So far, there are no documented cases of fully remediating a leak in a caprock in either a natural gas storage or waste injection project. This makes preventing the leakage becomes essential, because most of the time, leaks could have been avoided through proper and thorough geologic characterization of the caprock [Bruno, et al, 2014]. The integrity of shale caprock relies on the geomechanical properties of the rock, and it has effects on the quality and quantity of the gas/hydrocarbons beneath and within it. Potential loss of caprock integrity is commonly due to tensile fracturing, fault activation, and wellbore failure in the caprock. Understanding the microstructure and mechanical properties of the shale caprocks helps to maintain its integrity, predict the potential risk and prevent the failures from

Hydraulic fracturing is the process in which oil and gas is extracted from fractures found in wells that are hundreds of metres deep. In order to break these fractures extremely high volumes of water, chemicals and propellants are injected into the wells using large pipes. The propellants often consist of substances such sand, ceramic pellets or small incompressible particles which are used to hold open the fractures. (Earthworks, 2015) Due to the high amounts of internal pressure, the fluid is allowed to return to the surface containing naturally occurring materials such as brines, metals, radionuclides, and hydrocarbons. (Earthworks, 2015) Whilst an effective way of extracting these

Abundant amounts of resources are left to be untapped from unconventional reservoirs. (Arthur 2008) observes that about 500TCF of natural gas are contained in unconventional reservoirs. Unconventional gas reservoirs account for approximately one-third of the US natural gas production (Rafiqul, 2014). Over the years, reservoir engineers have relied on numerical simulators as a tool for modeling and predicting hydrocarbon recoveries (recovery factor) from reservoirs, which translates into the economic viablility (or not) of a petroleum asset. The accurate modeling of reservoir fluid-flow using simulators depend largely on the description of actual rock/fluid interactions that occur within the reservoir. Unlike for the case of conventional reservoir systems, the flow physics for unconventional reservoirs (Tight gas, Coal-bed methane, Shale reservoirs) are complicated by their unique features which include: extremely low permeability, complex fracture networks, non-darcy flow, Klinkenberg effects, adsorption/desorption effects and rock deformation due to variations in effective stress in the reservoirs. Accouting for all of these features into numerical

As the oil reservoir exist in layer4 and the upper and lower boundary is already known, we can create a multipatch to confine the upper and lower boundary of oil reservoir (the data is based on the provided contact depth) and using “Intersect 3D” tool to build the oil reservoir

In order to determine the most influential geological parameters affecting the Gas Assisted Gravity Drainage process, sensitivity analysis was conducted through Design of experiments (DoE). DoE combines multi-level of each parameter to create many computer experiments evaluated by the compositional reservoir simulation. The factors that were adopted in this case are horizontal permeability, anisotropy ratio $K_{v}/K_{h}$, and porosity, all given for the entire reservoir. The most influential factors are diagnosed through building a statistical linear modeling, partial t-test, and Analysis of Variance (ANOVA).