This characteristic own to its low clay content. The rock expansion rate is consistent with the clay content. The more clay is, the more severe the sample expansion rate is 4 Through nitrogen displacement experiment, in most cases, the flowback rate and permeability recovery rate have negative relationship with clay content and positive relationship with initial permeability.
Based on above research, clay expansion preventing additives should be added in the fracturing fluid to prevent clay expansion, reduce fluid retention into formation, and increase permeability recovery rate after flowback. When it comes to low permeability formation, preventing liquid filtration is a better choice, because not enough displacement pressure can be obtained. For relative high-permeability formation, quick flowback is a good choice to move liquid out of formation and increase permeability.
Our research contributes to better understand the formation characteristics and its influence on the gas displacement to remove aqueous phase trapping. This is an open access article distributed under the Creative Commons Attribution License , which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.
Article of the Year Award: Outstanding research contributions of , as selected by our Chief Editors. Read the winning articles. Journal overview. Special Issues. Academic Editor: Andrea Brogi. Received 25 Nov Accepted 03 Mar Published 23 Apr Abstract Tight sand gas is an important unconventional natural gas. Introduction With increasing energy requirement, unconventional natural gas attracts our attention [ 1 — 9 ].
Samples and Experimental Methods 2. Figure 1. The simple map of the study area. Table 1. Figure 2. The distribution of porosity a and permeability b of samples. Figure 3.
The mineral composition of samples: a Taiyuan formation; b H8 formation. Figure 4. Figure 5. The content of different clays: a Taiyuan formation; b H8 formation. Figure 6. The casting thin section: a — e belong to S and f — h belong to S The left picture and the right picture belong to the same area. Figure 7. The casting thin section: a — e belong to M and f — h belong to S Figure 8. Figure 9. Figure Sample expansion with time. The relationship between expansion rate at 3 hours and clay content.
The variation of liquid saturation and permeability recovery rate with displacement time in Taiyuan formation. The variation of liquid saturation and permeability recovery rate with displacement time in H8 formation. The variation of liquid flowback rate and permeability recovery rate with different displacement pressure.
The FZI of samples. References S. Huang, W. Sun, F. Xiong et al. Ji, Y. Song, Z. Jiang et al. Li, Y. Shen, H. GE, S. SU, and Z. Ge et al. Luo, N. Zhong, Y. Liu, Y. Qu, and L. Rui, J. Lu, Z. Zhang et al. Rui, X. Wang, Z. Huang, L. Chen, W. Sun et al. Ge, M. Meng, Z.
Jiang, and X. Zhao, W. Zhang, J. Li, Q. Cao, and Y. Rushing, K. Newsham, and T. Silin, T. Kneafsey, J. Ajo-Franklin, and P. Ulmer-Scholle, P. Scholle, J. Schieber, and R. Cai, W. Wei, X. Hu, R. Liu, and J. Sun, W. Ji et al. View at: Google Scholar P. Randolph, D. Soeder, and P. Rui, K. Cui, X. Wang et al. Gray and I. Kilmer, N. Morrow, and J. Vairogs, C. Hearn, D. Dareing, and V. Brace, J. Walsh, and W. Cui, A. Bustin, and R. Dicker and R. Freeman and D. Narahara and K.
Walls, A. Nur, and T. Rezaee, A. Saeedi, and B. Brooks and A. View at: Google Scholar J. Comisky, K. Newsham, J. The most important mechanical property is in-situ stress, often called the minimum compressive stress or the fracture closure pressure. When the pressure inside the fracture is greater than the in-situ stress, the fracture is open.
When the pressure inside the fracture is less than the in-situ stress, the fracture is closed. We can determine values of in-situ stress using logs, cores, or injection tests. To optimize the completion, it is very important to know the values of in-situ stress in every rock layer. In addition to knowing the values of in-situ stress, it is also extremely important to know the values of formation permeability in every rock layer.
The values of permeability control everything from gas flow rate to fracture fluid leakoff. It is impossible to optimize the location of the perforations, the length of the hydraulic fracture, the conductivity of the hydraulic fracture, and the well spacing, if one does not know the values of formation permeability in every rock layer.
In addition, one must know the formation permeability to forecast gas reserves and to analyze post-fracture pressure buildup tests. To determine the values of formation permeability, one can use data from logs, cores, production tests, and prefracture pressure buildup tests or injection falloff tests.
The most data that are available vs. If the logs are analyzed correctly, it is often possible to generate estimates of formation permeability vs. However, the correlations used must be calibrated with core, production data, or pressure transient data to ensure the values are representative of the permeability of the particular formation.
The following equations have been used in the industry over the years to correlate logs with permeability. Kozeny and Carman The various authors suggested ways of determining the values of surface area, grain diameter, and relative permeability. The equations of Timur and Coates are the most widely used correlations. In , a paper [32] was published that presented another method for correlating formation permeability with log data, as shown in Eq.
In summary, obtaining permeability from logging data is very useful because it provides the engineer with estimates of permeability vs. However, to be accurate, the engineer must correlate the logging data with permeabilities measured from core or computed from production or pressure buildup data.
In tight gas reservoirs, especially when analyzing prefracture production data, it is often difficult to flow the well to produce at rates high enough to measure. In addition, because the well has to be fracture treated to be economic, prefracture flow tests are often not even run, or if they are run, the flow period is very short. As such, the main goal is to measure flow rates and pressures and to analyze those data to determine an estimate of formation permeability and, perhaps, the skin factor.
Seldom do we have enough data to estimate the drainage area, as shown in Fig. As seen in Table 7. In most cases, the engineer trying to analyze the reservoir would like the production and PBU test to be run as long as possible.
On the other hand, because the well is more than likely producing at uneconomic flow rates, and a fracture treatment is required to improve productivity, the operations personnel want to minimize the duration of these tests to minimize costs and get the well producing to sales as soon as possible.
In addition to running the test long enough, the PBU tests in tight gas reservoirs should be analyzed using modern concepts such as pseudopressure, pseudotime, effective pseudotime, producing pseudotime, adjusted pressure, and adjusted time [38] Using these concepts helps increase accuracy when large pressure drawdowns exist in the reservoir and changing wellbore storage constants complicate the analyses of the PBU data.
In many cases, there are no long-term production data, and operational or cost-related problems prevent one from running a long-term PBU to quantify the formation permeability. However, it is very important to get a rough estimate of formation permeability prior to designing the fracture treatment.
Sometimes, the well can be perforated and produced for several hours or days prior to designing and pumping the fracture treatment. If the production and flowing data are accurately measured, the one point method can be used to estimate the value of formation permeability.
The semisteady-state gas-flow equation is One can iterate until the value of r d and k converge. A weakness in this method is that one has to estimate the value of skin factor; therefore, the procedure should be repeated by assuming different values of skin, s. One can generate a range of permeabilities for a range of assumed values of skin factor.
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 balance the need for more data with the need to minimize costs, the logical solution is to spend money gathering accurate data on a few wells, then use correlations developed from that data to evaluate the wells that will be drilled and completed thereafter. Once acceptable correlations are developed for specific reservoirs in specific geographic areas, the correlations can be applied to all wells in the area. By using these "calibrated" correlations, accurate datasets can be developed for new wells at a minimal cost.
Normally, the most critical data items are formation permeability and in-situ stress. If accurate correlations, in which logs can be used to estimate permeability and in-situ stress, can be developed, the well completion and stimulation plans can be optimized. Some have used flow units to segregate core and log data to develop better correlations. In their paper, Amaefule et al.
Using these two parameter groups, they developed a scheme to correlate formation permeability with effective porosity as a function of the FZI. As suggested by the Resource Triangle, Fig. For natural gas, the distribution is log-normal. As the value of reservoir permeability decreases, the value of OGIP increases exponentially.
There is obviously a difference between OGIP and reserves. The OGIP represents all the gas in the rocks that comprise the reservoir layers. Reserves represent the amount of gas that can be produced economically.
The value of reserves is a function of gas prices, costs, and the level of technology used to develop the resource. Often the amount of OGIP is computed by using porosity, water saturation, and shale volume cutoffs. In high permeability reservoirs, using such cutoffs may be appropriate, especially if the reservoir produces water above a certain water saturation cutoff and the OGIP estimates are not very sensitive to the cutoff values chosen.
However, in most tight gas reservoirs, only dry gas and small volumes of water that condense in the wellbore are produced. Very seldom are large volumes of water produced in tight gas reservoirs. The first step is to compute the value of porosity after making clay correlations with Eqs. The porosity can then be used to compute the water saturation, normally using the dual-water saturation model. In the tight gas sands research project sponsored by the Gas Research Inst.
The data in Fig. However, as the value of permeability decreases below a value of 0. For the case in which the net gas pay was only 25 ft and the permeability was between 0.
The data in Figs. It is important to generate correlations between logs, cores, and measured values of in-situ stress. The values of in-situ stress are very important to the engineer planning the well completion and stimulation treatment.
The engineer can usually correlate values of in-situ stress measured from pump-in tests with data measured using logs and cores. A common equation used to correlate lithology using Poisson's ratio with the in-situ stress is given in Eq.
The correlations included in this chapter were generated using log, core, and well-test data for the Travis Peak formation; hence, one cannot use these correlations for other formations in other basins around the world. These correlations are included in this chapter to illustrate how values of permeability and in-situ stress can be correlated with log and core data. The methods explained in this chapter can be used to generate other correlations in other formations in other basins.
Once specific correlations have been developed and verified, they can be used to evaluate layered, tight gas reservoirs to make basic decisions, such as whether the casing should be set.
Once the casing is set, the correlations can be used to generate the data required to design the completion and the stimulation treatment for the reservoir layers that are determined to be commercially viable. 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 [48] and can be divided into two groups. One group consists of data that can be "controlled. The primary data that can be controlled by the engineer are the well completion details and the fracture treatment details, such as fluid volume and injection rate.
The data that must be measured or estimated by the design engineer are formation depth, formation permeability, in-situ stresses in the pay zone, in-situ stresses in the surrounding layers, formation modulus, reservoir pressure, formation porosity, formation compressibility, and the thickness of the reservoir.
There are actually three thicknesses that are important to the design engineer: the gross thickness of the reservoir; the net thickness of the gas producing interval; and the permeable thickness that accepts fluid loss during the hydraulic fracture treatment.
The fracture propagation model requires information on the rock mechanical properties, such as in-situ stress, modulus, and Poisson's ratio. We also need data on the fracture fluid properties and the propping agent properties. The most critical data for the design of a fracture treatment are, roughly in order of importance, the in-situ stress profile; formation permeability; fluid loss characteristics; total fluid volume pumped; propping agent type and amount; pad volume size; fracture fluid viscosity; injection rate; and formation modulus.
In hydraulic fracture treatment design, by far the two most important parameters are the in-situ stress profile and the permeability profile of the zone to be stimulated, plus the layers of rock above and below the target zone that affect fracture height growth.
In new fields or reservoirs, most operating companies are normally willing to spend money to run logs, cut cores, and run well tests to determine important factors such as the in-situ stress and the permeability of the reservoir layers. By using such data, along with fracture treatment records and production records, accurate data sets for a given reservoir in a given field can normally be compiled. These data sets can be used on subsequent wells to optimize the fracture treatment designs.
It is normally not practical to cut cores and run well tests on every well. Thus, the data obtained from cores and well tests from a few wells must be correlated to log parameters, so the logs on subsequent wells can be used to compile accurate data. The data used to design a fracture treatment can be obtained from a number of sources, such as drilling records, completion records, well files, openhole logs, cores and core analyses, well tests, production data, geologic records, and other public records, such as publications.
In addition, service companies provide data on their fluids, additives, and propping agents. Well construction is a term used to incorporate the activities required to drill, complete, and stimulate a well as it goes from spud to a producing well. Well construction is a very broad topic, and to discuss every aspect in detail is outside the scope of this chapter. Instead, we concentrate on the aspects of well construction that are unique to tight gas reservoirs. Many of the items discussed next are also found in the Drilling Engineering volume of this Handbook.
Of concern in the design of the completion is always the number of producing zones that are separated in the reservoir by vertical flow barrier layers. To determine whether different producing intervals should actually be treated as a single reservoir, one must first determine if these various intervals are all connected by a single hydraulic fracture. If a particular zone is separated from another pay zone by a thin silt or shale layer with little in-situ stress contrast among the layers, one can use a model to determine if all the zones can be connected by a single hydraulic fracture.
If a single fracture treatment is used to stimulate multiple layers, and no reservoir damage occurs by commingling the different zones, the well should be completed as if all the layers are actually a single reservoir.
Normally, in dry gas reservoirs, no reservoir damage occurs by commingling zones. In fact, it is likely that more gas will be recovered by producing all the layers commingled because the abandonment pressure is lower at any given economic limit when the zones are commingled vs.
If two or more productive intervals are separated by a thick, clean shale say, 50 ft or more and this shale has enough in-situ stress contrast to be a barrier to vertical fracture growth, the design engineer might need to design the completion and stimulation treatments to consider the fact that multiple hydraulic fractures will be created. In such cases, fracture treatment diverting techniques must be used to properly stimulate all producing intervals. More information concerning completion design in multilayered reservoirs is available in the technical literature.
The two main concerns with tubular design are pumping the optimum fracture treatment and liquid loading as the gas flow rate declines. These two concerns must be balanced to achieve the optimum well completion. As previously stated, a tight gas well is uneconomic to drill, complete, and produce unless a successful fracture treatment is designed and pumped.
In general, fracture treatments are more successful when pumped at higher injection rates. Therefore, to pump a treatment at a high injection rate, we normally like to use large tubulars. Once the treatment is pumped and the well is put on production, the gas flow rate begins to decline. All wells, even dry gas wells, produce liquids in the form of condensate or water.
Regardless of how little liquid is produced, the well eventually loads up with liquids as the flow rate declines. Liquid loading is a function of gas velocity. Therefore, to minimize liquid-loading problems, we must use small tubing. Thus, the dilemma: we need large tubulars to pump the fracture treatment and small tubulars to minimize liquid loading.
The solutions to this dilemma can be as varied as the number of fields in which we work. Many considerations and computational techniques needed to solve these problems are presented in Gidley, et al. If the reservoir is geopressured, we might have to fracture treat the well down tubing at injection rates less than optimum. The topic of how to design casing and tubing and how to design the optimum tubular configuration in a tight gas well is too large to deal with completely in this chapter.
The completion engineer should, however, try to design the fracture treatment and the completion prior to spudding the well. If, during the design, the engineer determines that a certain size casing or a certain size tubing is required to implement an optimal design, the completion engineer should provide that feedback to the drilling engineer.
The drilling engineer can then design the bit program and casing program to accommodate the needs of the completion engineer. Once the hole is drilled and the production casing is set and cemented, it is too late to redesign the completion if you discover you needed larger casing to implement the optimum completion.
In the same manner, the fracture treatment should be designed prior to spudding the well, so a reasonable estimate of fracture treatment pressures, from bottomhole to the surface, can be estimated as a function of the casing size, the injection rate, and the fracture fluid friction and density properties.
It is very important to know the maximum injection pressure during the fracture treatment for a variety of completion scenarios. The drilling engineer can use that information to select the correct size, weight, and grade of casing. A fracture treatment is usually not successful if the injection rate or fluid viscosity is compromised when the casing cannot withstand the desired injection pressure.
Again, working the problem prior to spudding and designing the casing correctly can prevent problems and allow the service company to actually pump the optimum fracture treatment.
Perforating Concerns. Perhaps the least understood part of well completions and hydraulic fracturing revolves around how to perforate a well. Again, there is no simple solution, and the best perforating scheme varies depending on the specific reservoir situation. Two factors seem to be very important. First, the number of layers and the number of fracture treatment stages affect how we perforate the well. Second, the in-situ stress anisotropy plus the presence or lack of natural fractures have a strong bearing on how we perforate the well.
A problem associated with hydraulic fracture treatment problems has been recently identified in the petroleum literature as "near-wellbore tortuosity. These multiple hydraulic fractures are usually caused by the presence of natural fractures or the fact that too many perforations are shot in multiple directions over a long, perforated interval.
When multiple fractures occur near the wellbore, each fracture is narrower than a single fracture, and problems occur when trying to pump the propping agent down the narrow fractures. In many cases, a near-wellbore screenout occurs when near-wellbore tortuosity problems occur.
There are several ways to minimize near-wellbore tortuosity problems. More information concerning stresses and stress orientations is found in Gidley, et al. The completion engineer must be concerned with choosing the correct zones and perforating those zones to accommodate any diversion techniques that will be used in multistaged fracture treatments. In the perforating literature, there are many papers discussing how many holes are needed per foot of casing so that the productivity index is not reduced because of too few holes.
In a tight gas well that is fracture treated, the number of holes per foot of casing is really not much of a consideration. More importantly, the number of holes with respect to the fracture treatment injection rate should control the perforation operation.
A good rule of thumb is that the number of holes should be such that the injection rate per hole is between 0. For example, if you plan to pump the fracture treatment at 20 barrels per minute, then you should consider putting between 40 and 80 holes in the pipe in the zone where you want the fracture to initiate.
The worst situation is to shoot 4 or 6 shots per foot over a long interval. When too many holes are shot over too long an interval, the engineer loses control of where the fracture initiates, and the chances of creating multiple fractures at the wellbore increases substantially. As stated many times in this chapter, 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 chapter, we will discuss a few basic considerations for fracture treatment design and application. More information can be found in the chapter on Hydraulic Fracturing in the Production Operations Engineering volume of this Handbook. Candidate Selection. The success or failure of a hydraulic fracture treatment often depends on the quality of the candidate well selected for the treatment.
Choosing an excellent candidate for stimulation often ensures success, while choosing a poor candidate normally results in economic failure. To select the best candidate for stimulation, the design engineer must consider many variables. The most critical parameters for hydraulic fracturing are formation permeability, the in-situ stress distribution, reservoir fluid viscosity, skin factor, reservoir pressure, reservoir depth, and the condition of the wellbore.
The skin factor refers to whether the reservoir is already stimulated or, perhaps, damaged. If the skin factor is positive, the reservoir is damaged and will likely be an excellent candidate for stimulation.
The best candidate wells for hydraulic fracturing treatments in a tight gas reservoir have a substantial volume of OGIP and good barriers to vertical fracture growth above and below the net pay intervals. Such reservoirs have a thick pay zone, medium to high pressure, in-situ stress barriers to minimize vertical height growth, and substantial areal extent.
Tight gas reservoirs that are not good candidates for hydraulic fracturing are those with small volume of gas in place because of thin reservoirs, low reservoir pressure, or small areal extent. Also, reservoirs that do not have enough clean shale above or below the pay interval to suppress vertical fracture growth are considered to be poor candidates. Reservoirs with extremely low permeability might not produce enough hydrocarbons to pay all the drilling and completion costs, even if successfully stimulated; thus, such reservoirs would not be good candidates for stimulation.
Fracture Treatment Optimization. The goal of every design engineer is to design the optimum fracture treatment for each and every well. Gaupp, R. Tehrani, A. Veeken, C. Roy Hartley graduated as a petroleum engineer from Imperial College in He witnessed his first frac in the Rotliegendes in the same year. Filter Collections. Lessons to be Learned Thin section showing dolomite growth hence permeability reduction around quartz grains.
Rotliegendes Tight Gas So what is a typical tight gas reservoir? Technology Transfer? References 1. The main purpose of applying EM data is to improve exploration decision making. Remote sensing data has given a unique perspective on the East African Rift System, allowing both large regional structures and more subtle features to be identified and placed in context.
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Configure cookie settings Got it! Extensive seismic data is gathered and analyzed to determine where to drill and just what might be located below the earth's surface. These seismic surveys can help to pinpoint the best areas to tap tight gas reserves. A survey might be able to locate an area that portrays an improved porosity or permeability in the rock in which the gas is located.
Should wells directly hit the best area to develop the reserve, costs of development can be minimized. Most tight gas formations are found onshore, and land seismic techniques are undergoing transformations to better map out where drilling and development of these unconventional plays.
Typical land seismic techniques include exploding dynamite and vibroseis, or measuring vibrations produced by purpose-built trucks. While these techniques can produce informational surveys, advancements in marine seismic technologies are now being applied to land seismic surveys, enhancing the information available about the world below.
Not only providing operators with the best locations for drilling wells into tight gas formations, extensive seismic surveys can help drilling engineers determine where and to what extent drilling directions should be deviated. While vertical wells may be easier and less expensive to drill, they are not the most conducive to developing tight gas. In a tight gas formation, it is important to expose as much of the reservoir as possible, making horizontal and directional drilling a must.
Here, the well can run along the formation, opening up more opportunities for the natural gas to enter the wellbore. A common technique for developing tight gas reserves includes drilling more wells.
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