Jerzy M. Rajtar* SHALE GAS HOW IS IT DEVELOPED?

Transcription

1 WIERTNICTWO NAFTA GAZ TOM 27 ZESZYT Jerzy M. Rajtar* SHALE GAS HOW IS IT DEVELOPED? 1. INTRODUCTION XTO Energy, Inc. has been engaged in development of major gas shale plays in the continental US. The company is drilling mainly in the Barnett, Fayetteville, Haynesville, Marcellus, and Woodford shales. Other shales are under less intensive development. The gas shale reserves are a significant part of the total proved reserves of the company (approx 14 Tcfe) and in 2009 shale gas production accounted for 30% of total company daily gas production. To develop any hydrocarbon reservoir, the following basic questions must be answered: 1. Does a reservoir exist? 2. If it exists, how big is it, what and how much does it contain? 3. How much and how fast can we recover economically? The same questions arise in the development of shale gas reservoirs. The particular tasks to be completed while developing a shale gas asset fall into four groups: (1) geological identification of potentially productive gas shales (2) engineering characterization of shale gas reservoirs (3) typical completion techniques proven successful in shales (4) evaluation of reserves and development planning. The paragraphs below discuss these groups in some detail. 2. GEOLOGICAL IDENTIFICATION OF POTENTIALLY PRODUCTIVE GAS SHALES The initial major questions in shale gas development are: When shale becomes of interest as a potential gas producer? How do we screen for good shales? * XTO Energy, Inc. 355

2 Shales, in general, are considered source rocks. They are characterized by relatively high organic content. Under high pressure and high temperature, the hydrocarbon material can be released from the organic matter and stored within the porosity of the shale or migrate to other formations. The remaining organic matter usually has an affinity for hydrocarbon molecules, so some hydrocarbons (in particular gases) can be adsorbed at the surface of shale matrix. Non-hydrocarbon gases such as carbon dioxide or nitrogen are also known to adsorb in shales. Geological screening of shales focuses primarily on the following data: thickness of shale, Total Organic Carbon (TOC), vitrinite reflectance Ro, silica content. The high thickness is desirable for the volume of the reservoir. The obvious relationship is the higher the thickness, the better. TOC is a measure of all organic material within a rock/shale. This material comes in the form of bitumen (soluble in organic solvents) and kerogen (insoluble in organic solvents). Because natural gases are products of three possible processes: thermal decomposition of kerogen and/or thermal decomposition of bitumen (thermogenic gas), and anaerobic bacteria methane production (biogenic gas), the volume and quality of organic material in shales are of premiere interest. The TOC is measured in the lab and is reported as a percent of a sample material. High TOC indicates that the shale may have been a good source rock the higher the TOC, the more hydrocarbons may have been released to pore space or adsorbed by shale. The observed relationship of adsorbed shale gas content and TOC is typically linear. The vitrinite is an organic material referred to as type III kerogen [1]. The vitrinite reflectance has been used for coal ranking (thermal maturity of coals). As the vitrinite in coals is the same as vitrinite in kerogen, the vitrinite reflectance is useful for shale analysis. The vitrinite reflectance of Ro > 1.3 is desired for gas only production. These values point to the gas window on the diagnostic pyrolysis plot (Hydrogen Index vs. thermal maturity Tmax ). The Ro value is lower for gas condensate reservoirs. (Woodford shale with Ro = 0.8 Ro is producing gas with high condensate yield, see Fig. 1). Diagnostic plots from pyrolysis are useful in determining what kind of fluid production may be expected from shale reservoir (Figs. 1, 2). Silica content or carbonate content high for better hydraulic fractures. It is a general agreement that silica or carbonate grains create a weakness path for the fracture growth, which in 100% shale would not exist (shale material is considered a ductile material and needs 5 10% of deformation before it fractures). 356

3 Fig. 1. Diagnostic pyrolysis plot for a well in Woodford shale Fig. 2. Alternative diagnostic plot, same well as in Figure 1 357

4 3. ENGINEERING CHARACTERIZATION OF SHALE GAS RESERVOIRS The goal of engineering at early stage of development is to determine Original Gas In Place (OGIP). That requires estimates of reservoir area, thickness, porosity, water saturation, and adsorption isotherm of shale matrix. Well log data provide initial basic estimates for thickness, porosity and water saturation. Enhancement of these estimates is provided by calibrating logs to core data. Adsorbed gas content is determined through measurement of adsorption isotherms and using the results in calculations. Adsorption isotherms may be measured on cores and on drilling cuttings. If determined using cores, the adsorption isotherm is probably the most precise data item in calculations of OGIP. The adsorption isotherm is data that deserves a closer examination. Adsorption of hydrocarbon gases is adequately described by Langmuir adsorption equation, the plot of which is the Langmuir isotherm. The adsorption is in general controlled by pressure and temperature, but under most frequent assumption of constant reservoir temperature during operations it is a function of pressure only. The Langmuir equation may be written as follows: Vm p V =, P+ PL where: V volume of gas adsorbed [scf/ton], V m maximum adsorption capacity [scf/ton], P L Langmuir pressure (the pressure at which the V adsorbed is ½ of the maximum capacity) [psia], P reservoir pressure [psia]. The pressure at which shale sample achieves the maximum adsorption capacity sometimes is called a saturation pressure for adsorption. If the initial reservoir pressure is lower than this pressure, the reservoir contains initially less adsorbed gas per ton than the maximum measured in a lab. Many shale gas reservoirs are found at this initial state. Figure 3 shows an example of shale methane isotherm. Another approach to determining OGIP is to recover a core and measure its total gas content. In this approach the lost gas during the operation needs to be accounted for, and it is usually the weak point of the method. Once the total gas content of the sample in scf/ton is determined, the volume of the rock in the reservoir is converted to tons of rock, which multiplied by the total gas content yield OGIP. To determine what percent is in the adsorbed state, again, the isotherm is needed. Core data and well logging can deliver estimates of matrix permeability of shales. The matrix permeability needs to be determined for any flow modeling work. The values of shale matrix permeability cover a broad range from 1*10 12 md to 1*10 3 md, with most productive shales in the range of 1*10 6 md to 1*10 3 md. The estimated values depend on the method which is used to get the data. In the method frequently referred to as Gas 358

5 Research Institute method (GRI method), a sample is crushed before a test and the material is then packed into a sample holder [2]. The other method uses whole core plugs. Generally, the crushed sample measurements yield lower estimates. The actual permeability measurement is a pulse decay test that is free of gas rate measurement errors at low rates. Figure 4 shows a schematic of a testing setup. Fig. 3. Methane adsorption isotherm, Fayetteville shale Fig. 4. Modified pulse pressure testing setup (after S.C. Jones, SPE 24320, Ref. 3) 359

6 In a pulse decay test on the core plug without crushing, any fractures suspected to be a result of sample stress relief are filled with epoxy resin. Another method, referred to as a pressure decay method, uses crushed sample and gas expansion measurements. The gas expansion data are used to calculate permeability of shale. All of the above methods have some limitations. Pulse decay on the crushed sample may measure different permeability values than in-situ values, as pore bridges are destroyed in crushing and the resulting grain packing of crushed material in a sample holder may be different than in-situ packing. That procedure may also change porosity values, so the results of the pressure decay test may be affected by changing both pore connections and pore volume. In a test on a whole plug, sealing of suspected stress relief fractures may lead to sealing off fractures that existed naturally. A comprehensive gas shale evaluation is provided by Elemental Capture Spectroscopy (ECS) well log with accompanying interpretation package from Schlumberger [4]. The log estimates, among others, adsorbed gas content, free gas content and matrix permeability values from modeling of the log responses. The permeability values need calibration to measured core data. 4. COMPLETION TECHNOLOGY IN SHALES The surprising effect of gas production from a reservoir with 10 nd permeability is not that surprising if one considers what actually is created by successful fracturing of a well. The fracturing significantly increases an equivalent radius of the well, and in the fractured shale extremely low perms are offset by large fracture area exposed to the shale matrix. For example, if a vertical well of 0.5 ft diameter is completed through a 50 ft thickness of the 10 md reservoir, and its peak rate is 1 MMscf/d, it would take a fracture of 50 ft height and 200 ft half-length to produce the same rate from 0.02 md reservoir assuming the same pressure gradients and simple fracture geometry. Commercial gas rates from shale reservoirs are achieved by creating high areas of matrix connection to a well through hydraulic fracturing. The shale gas completions technology initially was adapted from tight gas horizontal well completions (vast majority of shale wells are horizontal). That technology is modified to local conditions, but essentially completions in all shales are similar. The ease with which a fracture is created is indicated by formation fracture gradient. The fracture gradient is calculated as the bottomhole pressure (BHP) required for initiation and propagation of a fracture, divided by depth. It is a measure how easy or how difficult it may be to create a fracture. In shales, fracture gradients reaching 1 psi/ft and above were observed. The shale fracture design takes these high values into account. It has been observed that higher silica/carbonate content of a shale rock promotes better fracture growth. The current gas shale completion technology favors long lateral wells with multistage hydraulic fracturing. Slick water, cross-linked gels, and linear gels are commonly used as fracturing fluids with high volumes of 30/70, 40/80, and 100 proppant sizes. The fracturing 360

7 begins with slick water, followed by cross-linked gel fluid, followed again with linear gel fluid if necessary. The goal is to maintain the proppant transport capacity for the proper proppant placement at the lowest possible fluid viscosity. The type of proppant is selected to withstand high closure stresses during flowback and production. The selection of proppant needs to minimize the embedment effects. Number of stages, number of perforations per cluster and stage spacing are designed to uniformly cover the length of the lateral and optimize the recovery. Figure 5 shows an example of a Barnett shale completion with details of each stage of fracturing. Figures 6 8 show examples of curves useful in optimizing completion design. The curves were developed for a horizontal well completion with a cemented lateral. The optimization objective was to maximize Expected Ultimate Recovery (EUR). Fig. 5. Example of Barnett shale completion, cemented lateral 361

8 Fig. 6. The effect of fracture half-length and cluster spacing on EUR Fig. 7. The effect of number of perforation clusters and fracture half-length on EUR 362

9 Fig. 8. The impact of matrix permeability on EUR of a hydraulically fractured well 5. DEVELOPMENT PLANNING A full field development requires determining the number of wells to be drilled, to arrive at economical ways of developing the asset under a number of conditions, current or future. The estimates of a single well EUR are necessary for prioritizing and scheduling of drilling. Single well drainage area estimates are necessary to determine a number of wells that may be drilled in the area for accelerated recovery or extra, captured reserves. The forecast of the future single well performance in conjunction with the schedule of putting wells on production delivers the overall field rate forecast. The total recoverable reserves and forecasted reservoir rates are used to assign a value to an asset and to plan the cash flow for the asset. This information serves the purpose of including the asset with a proper weight in a portfolio of a company. As the asset matures, the forecasts typically are closer to the actual field results. The above summary may describe any reservoir development work, not necessarily shale gas development. However, reservoir characteristics unique to shale reservoirs require particular attention. Their impact on estimates of EUR or drainage areas of single wells is profound. These characteristics reflect the physics of gas flow in shale gas reservoirs with hydraulically fractured completions. If not taken into account, they will lead to unrealistic total estimates (when an error in EUR estimate for a single well is multiplied by a large number of planned wells, or poorly estimated drainage area leads to underestimating or overestimating the number of wells needed for the asset development). It is one of the major challenges to provide reliable EUR estimates under practical restrictions on data quality. 363

10 Historically, decline curves and their analysis were the most fundamental basis of well forecasting. The decline curves are still in use for everyday engineering work but they are heavily supported by well performance analysis tools (for example RTA) and reservoir simulation. For conservative shale gas estimates, the decline curves serve reasonably well, especially when they are periodically modified and adjusted. They suffer, however, from two disadvantages. First, a decline curve is built on the basis of field rate data that are the result of not only the physical response of the reservoir to production, but also all the well control changes and mishaps. The curve built on the basis of such data may underestimate the well potential, and in particular will not account for any technological advancements (for example, if the current decline curve is used to plan future wells that may be drilled and completed with updated technology). That disadvantage is hard to quantify, and is certainly lesser of the two. The second disadvantage comes from the fact that decline curves do not account for any physical effects in a reservoir, and are simply the models of observed behavior up-to-date. They cannot account for the effects taking place in the reservoir which currently do not affect the production but in the future may have a large impact on decline, so the long term well performance may be underestimated. Examples of such effects may be compaction or a loss of fracture efficiency (negative effect on EUR), and changes of desorbed gas share in the well gas rate (positive impact, at least for a time). As the gas shale production in many areas is relatively recent, the decline curves are derived form short historical data periods. During these periods a full physical impact of an effect may be still developing. The impact of desorption is more profound in gas shales characterized by high percentage of adsorbed gas in OGIP. Figure 9 shows a plot of the fraction of desorbed gas in the total gas rate. The curve indicates that in this particular case the maximum of desorbed gas content in the wellhead gas rate does not materialize until after more than 20 years. The speed with which the fraction of desorbed gas grows is controlled by both reservoir parameters and completion characteristics. The dashed curve in Figure 9 shows that share of desorbed gas in the cumulative gas production is growing without reaching a maximum in the period of forecast. The data are simulated for a sub-area of Barnett shale for which the adsorption gas share in OGIP is 19%. Figure 10 shows that the time to achieve maximum desorption share of gas rate may vary in a broad range. The observed shale gas decline curves are characterized by a very steep initial decline (up to 90%/year or more) followed by medium decline, and ending in a shallow decline (2 10%/year).The slope of the final decline is usually a disputed value. It is controlled by the matrix permeability value which in absence of precise, representative data is often assumed as a range. The reservoir simulation studies have the best chance of providing meaningful although approximate information. The reservoir simulation study puts together in one physically consistent model all the known data representing reservoir and well completions. The model is then calibrated/history matched to the well historical data and run in the predictive mode to deliver a forecast. Reservoir simulation being more consistent with the physical behavior of a reservoir is certainly a better tool for forecasting than decline curves (and for some specific tasks simulation is the only choice). However, if calibrated to a very short period of historical data it has some limitations. 364

11 Fig. 9. A fraction of adsorbed gas in gas rate and in cumulative production, Barnett shale well Fig. 10. A fraction of desorbed gas in production rate, Woodford shale and sub-area of Fayetteville shale 365

12 Figure 11 shows an example of rate pre-diction for the well with short history. The history was matched for two values of matrix permeability 100 nd and 10 nd. The results clearly indicate the impact of matrix permeability on late time gas rates. The example also illustrates the point that it may take a long history to match before an engineer can choose which of the assumed matrix permeability values was proper. Fig. 11. The effect of shale matrix permeability on gas rate predictions with history match of a short period of production The results of reservoir modeling depend highly on the skills of engineers involved in the work, as they have to decide on the level of complexity necessary for good quality results under limited quality and availability of input data. The results are then always in the best under the circumstances category as even as some processes may be present during the production, there is no quantitative description available. For example, effects of fracture compaction or matrix permeability reduction under extra stress are hard to measure, model, and quantify in the way that would be applicable in shale gas engineering work. Similarly, in a multistage fracturing one cannot be sure what is the fracture width, effective length, conductivity of any stage, and these are the data needed for defining well completions in the reservoir model. In the absence of these, some average data and fracture geometry are assumed and adjusted in the process of history match. The results of reservoir simulation are always associated with some uncertainty level. For example, the results of a good history match of a short production history, shown in Figure 11, point to two EUR values differing by a factor of 2. In presence of all the 366

13 uncertainties, a modeler of gas shale well performance needs to evaluate a range of possible outcomes, and to identify the most likely outcome. 6. CONCLUDING REMARKS A successful development of gas shale reservoirs remains a challenge for drilling, completion, and reservoir engineers. For the most part, the commercial success is the result of courage to try and learn from results. Understanding of all processes in gas shale reservoirs remains limited amongst the operators. This is a result of limitations of our measurement and testing abilities in very low permeability reservoirs. Much of the knowledge is gained from modeling work. It is conditioned by the data we are able to acquire, their precision, and a level to which they represent a reservoir or completion. The measurement and testing technology needs to make significant advancements to remove at least part of the uncertainties that are associated with this data. Judging by what we achieved over so many years in conventional reservoirs, it will take some time. The author would like to express his gratitude to XTO Energy for support and allowing this material to be published. REFERENCES [1] Waples D.: Organic Geochemistry for Exploration Geologists. Burgess Publishing Co [2] Development of Laboratory and Petrophysical Techniques for Evaluating Shale Reservoirs. GRI Report GRI-95/0496, GRI 1996 [3] Jones S.C.: A Technique for Faster Pulse Decay Permeability Measurements in Tight Rocks. SPE Formation Evaluation, March 1997 [4] Lewis R. et al.: New Evaluation Techniques for Gas Shale Reservoirs. Schlumberger Reservoir Symposium,