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The definition of a tight gas reservoir is one that must be successfully fracture treated to produce economic volumes of gas at economic flow rates. In this page, we will discuss a few basic considerations for fracture treatment design and application. Many tight gas reservoirs are thick, layered systems that must be hydraulically fracture treated to produce at commercial gas flow rates. To optimize the completion, it is necessary to understand the mechanical properties of all the layers above, within, and below the gas pay intervals. Basic rock properties such as in-situ stress, Young's modulus and Poisson's ratio are needed to design a fracture treatment. The in-situ stress of each rock layer affects how much pressure is required to create and propagate a fracture within the layer. The values of Young's modulus relate to the stiffness of the rock and help determine the width of the hydraulic fracture.
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 reservoirs generate many difficult problems for geologists, engineers, and managers. Cumulative gas recovery (thus income) per well is limited because of low gas flow rates and low recovery efficiencies when compared to most high permeability wells. To make a marginal well into a commercial well, the engineer must increase the recovery efficiency by using optimal completion techniques and decrease the costs required to drill, complete, stimulate, and operate a tight gas well. To minimize the costs of drilling and completion, many managers want to reduce the amount of money spent to log wells and totally eliminate money spent on extras such as well testing. However, in these low-permeability layered systems, the engineers and geologists often need more data than is required to analyze high permeability reservoirs.
To evaluate a layered, tight gas reservoir and design the well completion, the operator must use both a reservoir model and a hydraulic fracture propagation model. The data required to run both models are similar and can be divided into two groups. One group consists of data that can be "controlled." The second group reflects data that must be measured or estimated but cannot be controlled. The data required to run a reservoir model depends on the type of model one chooses to use.
The resource triangle, Figure 1, describes the distribution of original gas in place (OGIP) in a typical basin. At the top of the triangle are the high permeability reservoirs. These reservoirs are small, and, once discovered, as much as 80 to 90% of the OGIP can be produced using conventional drilling and completion methods. As we go deeper into the resource triangle, the permeability decreases, but the size of the resource increases. Higher gas prices and better technology are required to produce significant volumes of gas from these tight gas reservoirs.
Logs provide the most economical and complete source of data for evaluating layered, complex, low porosity, tight gas reservoirs. All openhole logging data should be preprocessed before the data are used in any detailed computations. Once the data have been preprocessed and stored in a digital database, a series of statistical analyses must be conducted to quantify certain evaluation parameters. The series of articles by Hunt et al. clearly describes the steps required to: To correctly compute porosity in tight, shaly (clay-rich) reservoirs, one of the first values to compute is the volume of clay in the rock. The clay volume is normally computed using either the self-potential (SP) or the GR log readings. The following equations are commonly used to compute the clay volume in a formation.
Calgary-based Tourmaline Oil Corp. announced today that it is acquiring Black Swan Energy in an all-stock deal valued at CAD $1.1 billion. The transaction is set to boost Tourmaline's output by 50,000 BOE/D and the company expects to average around 500,000 BOE/D by mid-2022. The operator said the Black Swan acquisition is one of several it has made recently to become the largest producer in the north Montney Shale area of British Columbia. Black Swan's 231,000-acre position gives Tourmaline an estimated 1,600 horizontal drilling locations and proven and probable reserves of 491.9 million BOE. Tourmaline said in its announcement that Black Swan has not booked material reserves in other areas that it sees as having high potential and complementary to its existing footprint.
The definition of a tight gas reservoir is that the reservoir does not produce at commercial gas flow rates, or recover commercial volumes of natural gas, unless a hydraulic-fracture treatment is properly designed and pumped. As such, the entire drilling and completion procedures should focus on making sure the optimum fracture treatment can be designed and pumped in the field. When drilling a tight gas well, the most important aspect of the drilling operation is to drill a gauge hole. Many times this means the well should be drilled at a balanced mud weight or slightly overbalanced. In other cases, air drilling or underbalanced drilling works best, as long as the hole remains in gauge.
Abstract Unconventional and tight gas reservoirs are located in deep and competent formations, which requires massive fracturing activities to extract hydrocarbons. Some of the persisting challenges faced by operators are either canceled or non-productive fractures. Both challenges force oil companies to drill new substitutional wells, which will increase the development cost of such reservoirs. A novel fracturing method was developed based on thermochemical pressure pulse. Reactive material of exothermic components are used to generate in-situ pressure pulse, which is sufficient to create fractures. The reaction can vary from low pressure pulse, to a very high loading up to 20,000 psi, with short pressurization time. In this study, Finite Element Modeling (FEM) was used to investigate the impact of the generated pressure-pulse load, by chemical reaction, on the number of induced fractures and fracture length. Actual tests of pulsed fracturing conducted in lab scale using several block samples compared with modeling work. There was a great relationship between the pressure load and fracturing behavior. The greater the pulse load and pressurization rate, the greater the number of created fractures, and the longer the induced fractures. The developed novel fracturing method will increase stimulated reservoir volume of unconventional gas without introducing a lot of water to formation. Moreover, the new method can reduce formation breakdown pressure by around 70%, which will minimize number of canceled fracturing.
Jia, Ying (Exploration and Production Research Institute, Sinopec) | Shi, Yunqing (Exploration and Production Research Institute, Sinopec) | Yan, Jin (Exploration and Production Research Institute, Sinopec)
Abstract Tight gas reservoirs are widely distributed in China, which occupies one-third of the total resources of natural gas. The typical development method is under primary depletion. However, the recovery of tight gas is only around 20%. It is necessary to explore a new technique to improve tight gas recovery. Injecting CO2 into tight gas reservoirs is a novel trial to enhance gas recovery. The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery of tight gas reservoir. Taken DND tight sandstone gas reservoir in North China as an example, 34 wells of DK13 wellblock were chosen as CO2 Enhanced gas recovery pilot area with 10-year production history. Six injection scenarios were studied. Numerical simulation indicated that the recovery of the gas reservoir of DK13 well area was improved by 8-9.5 percent when CO2 content of producers reaches 10 percent. The annual CO2 Storage would be 62 million cubic meters (110 thousand tons) and the total CO2 storage would be around 800million cubic meters (1.5 million tons). After the environmental parameter evaluation of injectors and producers, the anticorrosion schemes were put forward and the feasibility evaluation and schemes of facilities were presented. The analysis results indicated that DK13 wellblock was suitable for CO2 enhanced gas recovery no matter geologic condition, injection & production technology and facilities. However, under the current economic conditions, DK13 wellblock was not suitable for CO2to enhance gas recovery. However, if gas price rise or low carbon strategy implement, the pilot test could be carried out. In brief, CO2 could be an attractive option to successfully displace natural gas and decrease CO2 emissions, which is a promising technology for reducing greenhouse gas emission and increasing the ultimate gas recovery of tight gas reservoirs. This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.