The Haynesville Shale is one of the largest unconventional gas fields in the US. It is also one of the deepest, with wells reaching more than 10,000 feet below ground. This uncommon depth and overpressure leads to initial reservoir pressures of up to 12,000 psi. These pressures are uniquely high among shale gas reservoirs, and require special treatment. We show that the methods developed by Patzek, et al., PNAS, 110, 19731-19736, can scale all individual wells' gas productions to fit upon a single, universal curve. Haynesville wells can take months or years for flowing tubing pressure to stabilize, so we modified the type curves to take this into account. Furthermore, we introduce a PVT solver in order to calculate gas properties at up to reservoir pressures. When we apply the scaling theory to 2,199 individual well productions in the Haynesville, we find 1,580 wells which have entered exponential decline due to pressure interference. We use a simple physical model to determine the time to interference for wells with geologic parameters typical of the Haynesville, and use this to determine a field-wide permeability from the wells where we have observed pressure interference. From this, we arrive at time to interference for the remainder of Haynesville wells, and use this to arrive at production forecasts for all individual wells.

Due to suppressed natural gas price in the past several years in North America, liquid-rich retrograde gas reservoir development has been the main focus for many gas reservoir operators in Canada. Due to the subsurface complexity of PVT behavior for condensate, liquid (condensate) production forecast has been a challenge for operators. In addition, many liquid-rich retrograde reservoirs have also encountered extremely low permeability, which makes the liquid production forecast an even more challenging task for operators. Today, the most common methodologies to analyze production performance for retrograde gas reservoirs are limited to either numerical (simulation) or empirical (such as Arps’ decline). However, for numerical analysis, original PVT properties, special core analysis (SCAL) and pressure history are required as input data, which are usually very costly to obtain and they are, therefore, routinely ignored by operators. This paper presents a simple way to predict condensate production from the gas production by means of readily available early years’ production data. This simple methodology includes a new specialized plot to find related parameters for condensate production forecast without any costly PVT and pressure history data. Moreover, a set of diagnostic plots has been developed to identify the degree of the blockage to the gas production from the near wellbore oil-bank. This new methodology has been tested on more than one hundred horizontal wells that have been producing retrograde gas from several Western Canadian formations, such as the Notikewin, Glauconite, Montney, Falher as well as the Eagle Ford formation in the United States. All such tests were carried out by using only the early part of the production data to history-match the later part of the production history. The results have shown good agreement with the forecast based on the new methodology. Both synthetic and real well examples will be presented in this paper to illustrate the use of this new methodology.

Liquid-rich shale plays (LRS) in North America have recently gained a lot of attention. Commercialization of these plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Along with such developments, there is an increased requirement to develop consistent reservoir-engineering methods to analyze multi-phase production data in such reservoirs. Large drawdowns required to produce these very low permeability formations complicate production analysis due to condensate drop-out near the wellbore or fracture face. Hydraulically-fractured vertical and horizontal wells completed in tight formations typically exhibit long periods of transient linear flow. This paper discusses a novel production data analysis technique for constant flowing bottomhole pressure (p wf < p dew ) wells producing from fractured LRS reservoirs. Our focus in this work is on cases where the initial reservoir pressure is well above the dew point pressure, as occurs in highly-undersaturated portions of the Eagle Ford Formation. A theoretical basis is developed for analysis of the transient linear flow period for these cases, and the effect of initial pressure on well performance is studied. The governing flow equation is linearized using appropriately defined two- phase pseudopressure and pseudotime functions, where the liquid solution analogy ca n be applied. This approach provides an accurate estimation of the linear flow parameter (x f √k) in multi-phase flow situations. Fine-grid compositional and black oil numerical models are used to validate the results. This work provides a robust analytical framework for production analysis of liquid-rich shale reservoirs as well as practical guidelines for real world applications.

Recently, as a result of the increasing exploration and production activity in unconventional plays, new decline curve models have been developed. The main purpose of these newer models—e.g., SEPD, Duong, Logistic Growth, Power Law, Dual-Models—is to overcome the boundary-dominated flow assumption required for validity of the basic Arps’ model, which restricts its application in ultra-low permeability reservoirs exhibiting long-duration transient flow. These new decline curve analysis (DCA) methods are still ordinarily applied only to rate-time data, and thus rely on the assumption of stable (constant) flowing pressure. Since this stabilized state is not reached rapidly in most unconventional wells, the applicability of these methods and the reliability of their forecasts may be compromised. In addition, production performance predictions cannot be disassociated from the operational constraints that existed when production history was observed. This paper introduces a modified decline curve analysis method we call Pressure Normalized Decline Curve Analysis (PN-DCA) to provide a solution to these problems. Unlike traditional DCA methodology, which analyzes only production rates, this method analyzes pressure-normalized rates. To validate the applicability of this technique, we used hindcasting analysis of real production data from four different shale plays in the US (Eagle Ford, Woodford, Marcellus and Bakken). We found that this technique can be used as a reliable production forecasting technique suited to interpret unconventional well data in specific situations such as unstable operating conditions, limited availability of production data (short production history), and high-pressure, rate-restricted wells. Moreover, this method has proved to have the important ability to dissociate the estimation of future production performance from past operation constraints. This work also proposes an innovative decline curve analysis workflow, which includes a multi-method approach to optimize the flow regimes identification process. This methodology integrates different diagnostic plots that have been improved by incorporating important concepts such as MBT, pseudo-variables (for gas wells) and pressure-normalized rates. Each DCA model has been designed assuming specific flow regimes. Therefore, a proper identification of dominant flow regimes will help us to perform decline curve analyses with more confidence and to avoid unrealistic production forecasts. In general, incorporating pressure-normalized rates in decline curve analysis offers the possibility of producing improved forecasting results, which implies greater accuracy in production performance predictions and more reliable reserves estimations. The petroleum industry may become more confident in reserves estimates, which are the basis for the design of development plans, investment decisions, and valuation of companies’ assets.

Wellbore monitoring techniques are proving to be significant in reservoir management and intervention design, particularly in unconventional fields where fluid flow behavior is not very well understood. Distributed temperature sensing (DTS) technology allows for an estimation of zonal flow rates in the entire well as a function of time during hydraulic fracturing, as well as during the production phase. In this work, a novel transient thermo-hydraulic model that includes fluid transport and thermal coupling and simulates fluid flow and temperature in both the wellbore and reservoir is presented. Real DTS data from a hydraulic fracturing operation in a low-permeability basin in west Texas has been inverted using this model. Flow allocation based on the thermo-hydraulic model is presented. It was found that the reservoir heterogeneity, and hence the zonal flow rates, can be accurately obtained based on temperature and pressure data from the well. Most of the steady-state DTS data inversion models are typically applicable to production scenarios, where the transient in temperature has vanished. Injection operations, such as in fracturing where the temperature does not achieve a steady- state during the injection stage, require a transient model that can capture the initial-time effects. Also, some of these models fail to include the Joule-Thomson effect, and this leads to an incorrect flow allocation. The thermo-hydraulic model developed in this work includes both the Joule-Thomson and transient effects. It can be applied to non-reactive fluid injection during stimulation operations, such as matrix acidizing and fracturing. In particular, application of the model for fluid distribution before, during, and post-fracturing provides an estimate of the efficiency of fracturing stages.

In the last few years, the oil industry has turned its focus from shale gas exploration to shale oil/tight oil. Some of the important plays under development include the Bakken, Eagle Ford, and Niobrara. New decline curve methods have been developed as possible alternatives to the traditional Arps model for use in shale gas wells, but much less study has been done to verify the accuracy of these methods in shale oil wells. There is a great amount of uncertainty about how to calculate reserves in shale reservoirs with long multi-fractured horizontals, since most of these wells of have not yet been produced to abandonment. Although the Arps model can reliably describe conventional reservoir production decline, it is still uncertain which empirical decline curve method best describes a shale oil well to get a rapid assessment of expected recovery. The models on which we concentrated were Arps with a 5% minimum decline rate, the stretched exponential model (SEPD), and the Duong model. Our focus began in the oil window of the Eagle Ford, but we ultimately chose to study the Elm Coulee field (Bakken formation) instead to see what lessons an older tight oil play could lend to newer plays such as the Eagle Ford. Contrary to the assumption that these wells were still in linear flow, we found evidence from diagnostic plots that many horizontal wells in the Elm Coulee that began producing in 2006 and 2007 have entered boundary-dominated flow. In order to accommodate boundary flow we modified the Duong and SEPD methods such that once boundary-dominated flow begins the decline is described by an Arps curve with a b-value of 0.3. We found from hindcasting that using early production history, up to the first six months, is generally detrimental to accurate forecasting in the Elm Coulee. This was particularly true for the Arps with 5% minimum decline or the Duong method. Early production history often contains apparent bilinear flow or no discernible trend. There are many possible reasons for this, such as the rapid decrease in bottomhole pressure and production of fracture fluid.

Environmental concerns in Pennsylvania related to Marcellus Shale development are high. One of the issues to which the Pennsylvania Department of Environmental Protection (PADEP) has given a high priority is the threat of methane migration into fresh water as a result of methane leaking to surface from behind casing. This has become a significant problem for Marcellus operators as leaking annuli on both new and existing wells is not uncommon. This paper outlines the steps that Flatirons Development took to demonstrate to PADEP that the annular leaks on a recently drilled and cased Marcellus lateral posed no credible threat to ground water and that completion of the well should be allowed to proceed. In early June, 2011, Flatirons became aware of bubbling in the water filled cellar of the DU 3-6-1H. This discovery came just as completion operations were set to begin. Subsequent investigation revealed that there were two leaks, one from the production-intermediate annulus and another very small leak from the intermediate-surface annulus. PADEP issued Flatirons a Notice of Violation (NOV) and requested that fracture treating the well not proceed until the issue had been resolved. Over the following two months, Flatirons implemented a series of diagnostic procedures meant to assess the short and long term environmental threat, determine the cause of the problem, trace the source of the gas, and, if necessary, formulate effective remediation options. Using a variety of tools including ultrasonic imaging, pressure build-ups, noise-temperature logs, gas isotopic analysis, cement sample analysis, and continuous monitoring of annular flow, Flatirons was able to demonstrate that the fresh water aquifer was not threatened by methane migration. This work was presented to PADEP's Gas Well Integrity study group and helped form a basis for revising regulations governing leaking annuli.

Advances in directional drilling and reservoir stimulation techniques have dramatically increased gas production from wells drilled in shale reservoirs that were considered uneconomical not too long ago. In spite of many advances made on understanding the production behavior of this type of reservoirs, there are many unknowns that still do not have a proper answer. Particularly, it is difficult to predict productivity from cores, logs or DST s or from early well production performance. Drainage volumes are uncertain and well spacing is based on trial and error methods. The use of micro-seismic and production logs has helped in the fracture evaluation to determine the drainage volume and fracture inflow. Micro-seismic can provide useful information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the stimulation treatment parameters and reservoir characteristics. Additionally, these fracture geometries in conjunction with other measured or calculated parameters (rates, inflow models) can be used to better understand fracture modeling and production characteristics. Reviews of production logs have indicated that only a percentage of the fractures are contributing to the production, however considering that this is a transient system, a snapshot measurement is not enough to understand the behavior of the fractures and their contribution over time. It is necessary to have continuous or permanent information from within the wellbore to establish which fractures are contributing and how much. The near-wellbore temperature distribution yielded by distributed temperature sensing ( DTS ) or multi-point or array temperature sensing ( ATS ) can be used to determine the relative amount of fluids that each perforation interval contributes. If this information is combined with one or more pressure measurements and a real-time surface multiphase flow measurement in conjunction with an inflow model for each fractured interval, a production allocation could be calculated for each fracture. This approach is analogous to a traditional well allocation where a daily aggregated measurement at the production plant is back allocated to each well based on wellhead measurements like pressure, temperature and well performance. This paper will provide details on the above mentioned analogy and the use of these technologies to analyze the fracture behavior in horizontal wells in shale reservoirs.

Declining reservoir pressure and rate in the Jonah field has led to the common problem of liquid loading. As fluids accumulate the downhole pressure increases which decreases the available drawdown that allows fluids to flow into a wellbore. Jonah wells are completed in the 2000 - 3500-ft thick Lance Formation, using 8-16 hydraulic fracturing stages. With initial end of tubing (EOT) depths set above the top perforation for most wells, this left approximately 1500-3000 feet (gross pay) of perforations below the EOT. With lifting velocities significantly greater in larger diameter casing than tubing, a liquid column was developing below the EOT and engineering and operational attention was needed to improve field performance. Improving on the operational efficiency involved the implementation of recommended actions from a cross-functional well by well review group that received input and support from all Jonah asset members. The approach focused on how to improve liquid removal and optimize gas production from wells identified as liquid-loaded. In addition to installing plunger lift systems and injecting soaps, in 2008 a program was started to lower production tubing in wells by approximately 50-70% into perforations; the purpose was to reduce the column of fluid in the wellbore by helping more efficiently unload fluids using the reduced critical flow rate in the tubing and allowing plungers deeper access to the column of liquid covering the perforated interval. This paper discusses the results of lowering the EOT of over 100 gas producing wells in the Jonah field. The wells showed an average sustained uplift of approximately 105 mcfd, with undiscounted payout of less than 12 months. In addition, on wells that have had the tubing lowered, their decline curves appear to flatten out, offsetting anticipated double digit decline. Practical methods of selecting candidate wells and the new EOT are presented and discussed.

Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using square root-time plot, a plot of rate-normalized pressure versus square root of time. Linear flow appears as a straight line on this plot and the slope of this line can be used to calculate the product of fracture half-length and square root of permeability. In this paper, linear flow from a fractured well in tight/shale gas reservoir under a constant flowing pressure constraint is studied. It is shown that the slope of square root-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial pressure, flowing pressure and formation compressibility. An analytical method is presented to correct the slope of the square root-time plot to eliminate the overestimation of fracture half-length. The method is validated using a number of numerically-simulated cases. As expected, the square root-time plots for these simulated cases appear as a straight line during linear flow for constant flowing pressure. It is found that the newly-developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully-analytical, results in an improvement in linear flow analysis over previously-presented methods.

Hydraulically-fractured vertical and horizontal wells completed in shale gas and some tight gas plays are known to exhibit long periods of linear flow. Recently, techniques for analyzing this flow period using (normalized) production data have been put forth, but there are known errors associated with the analysis. In this paper, linear flow from fractured wells completed in tight/shale gas reservoirs, subject to a constant production rate constraint, is studied. It is shown analytically that the square root-time plot, a plot of rate-normalized pressure versus square root of time which is commonly used to interpret linear flow, depends on the production rate. It is also shown that depending on production rate, the square root-time plot may not be a straight line during linear flow; the higher the production rate the earlier in time the plot deviates from the expected straight line. This deviation creates error in the analysis. To address this issue, a new analytical method is developed for analyzing linear flow data for the constant gas rate production constraint. The method is then validated using a number of numerically-simulated cases. As expected, based on the analytical derivation, the square root-time plots for these cases depend on gas production rate and for some cases it does not appear as a straight line during linear flow. Finally, it is found that there is excellent agreement between the fracture half-lengths obtained using this method and the input fracture half-lengths to numerical simulation.

Production performance forecasting and the estimated ultimate recovery (EUR) evaluation are two of several uncertainties in the study of tight gas reservoirs. Using the Arps’ decline curve analysis to extrapolate the estimated ultimate recovery (EUR), based on the future production forecasting, is still a widely employed engineering tool in the oil and gas industry today. Tight gas reservoirs usually have a long transient/transitional flow period due to its low permeability. Simply by using the best fit "b" value to estimate the best EUR could generate an error as much as 100% from the true EUR. There has been a number of technical papers published dealing with this issue. This paper will present a new improved methodology to determine a more accurate "b" value to be used in the Arps’ decline curve analysis for tight gas reservoirs. This new approach, using a newly developed relationship between Q cum , Q cum, t →∞ , q t and t, is more rigorous and much easier to use in comparison with all other existing ones. This new improved methodology will not only make future production forecasting more accurate, but also estimate the original-gas-in-place (OGIP) controlled by the well much easier. In Western Canadian Deep Basin, there are many extremely "tight" gas reservoirs that consist of multiple stacked shorefaces. Permeability in each shoreface varies very significantly, generally with the upper shoreface having a better permeability and the middle and lower ones having a permeability as poor as 0.01 mD. By using a reservoir simulator, a number of simulation runs have been performed by the author to answer the following questions: Could Fetkovich's b-values recommendation (mostly b<= 0.4 ~ 0.5 for single gas layer, b>=0.5 for multi-layer without crossflow) still be applied to the tight gas reservoirs? In a multi-stacked shoreface reservoir, does the lower perm zone contribute to the overall production? Moreover, how and when will it influence the production profile? When using the Arps’ decline curve analysis, what are the reasonable b-values to be used for the tight/stacked gas reservoirs? Both synthetic production decline profiles generated from simulation runs and a field example are presented in this paper to illustrate this new proposed methodology and to answer the above three questions.

Marginal economics underscores the importance for accurate estimation of production profile and expected ultimate recovery or EUR in unconventional resources. While the Arps family of type-curves and the stretched-exponential model appears to yield reasonable estimation of EURs, all insufficiently explain the intrinsic behavior of unconventional reservoirs. This study introduces and applies a new semianalytical approach for estimating production profile and EUR, validated by numerical simulations and verified by field data for unconventional gas and oil reservoirs. We obtained analytical solutions by considering concentric compressibility elements, analogous to electrical capacitors, in series using the continuity equation to obtain production from conceptual geobodies. This configuration mimics decreasing contributions from a series of concentric reservoir segments into the well with increasing distance from the stimulated-reservoir volume or SRV. The analytical formulation captures production behavior of early-time and SRV-dominated flow patterns, leading to good estimation of expected-ultimare recovery or EUR.

Shale gas currently provides 20% of domestic supply, is targeted by half of the gas-directed drilling rigs, and represents the large majority of domestic resources. However, modern shale plays, their development strategies and their engineering analysis are young by comparison to those of conventional reservoirs. Uncertainty in shale gas reserves has significant implications at both the micro and macro levels. Conventional reservoir engineering tools must be viewed as potentially inadequate (or even inappropriate) for the evaluation of shale gas performance primarily because of the extremely low aggregate permeability of these systems, but also because of other unique aspects of the systems. Reservoir modeling (simulation) has an important role as an assessment and prediction tool; however, the character of the reservoir (induced and enhanced natural fractures) must be considered, as well as the geological and fluid characteristics. Rate-transient analysis (modern decline analysis) techniques are also more rigorous and have been expanded and adapted to fit the uniqueness of shale gas production. Application of each method for shale gas is discussed, including methods and limitations. These two techniques more closely represent the physics of shale gas production, but their implementation is often prohibitive. By way of necessity, much engineering evaluation is performed using Arps decline curve analysis. This technique is argued by some to be inappropriate due to a lack of theoretical support and demonstrated tendency to over-estimate reserves in tight gas systems. Given the limitations, practical methods exist to reduce error associated with its use. A newer decline method, power-law exponential, is also investigated.

Production logs from more than 100 horizontal shale wells in multiple basins have been acquired and interpreted. An evaluation of this data set confirms that production is highly variable along the length of the wellbores. In some basins, two-thirds of gas production is coming from only one third of the perforation clusters. Furthermore, when looking at all basins, almost one third of all perforation clusters are not contributing to production. This highlights a significant opportunity to improve overall completion effectiveness and economics in these high profile projects. Observations of near-wellbore reservoir quality and completion efficiency can be attained from the analysis of this data. Rock properties such as mineralogy, natural fracture density, and closure stress in the near wellbore region impact reservoir quality and hydraulic fracture conductivity. Completion parameters such as the staging of stimulation treatments, the number of perforation clusters per frac stage, and perforation cluster spacing can all impact the productivity of an individual perforation cluster. Correlations between productivity and key geologic, petrophysical and completion parameters can be made. The result is a better understanding of the parameters that are controlling completion effectiveness, and corresponding productivity in horizontal organic shale wells.

Traditionally reserves management has been an exclusive function for Reservoir Engineers; however in mature fields the need to involve Production, Facilities, Geology, Operations Engineers and Financial Analysts is critical. This paper presents a suggested workflow to improve the way reserves are evaluated, supported, booked and documented with a concerted effort of a multidiscipline team. This paper is focused on tight gas reservoirs and the central idea is to reduce the uncertainty that is always present when dealing with reserves. Most of the discussion is concentrated in understanding and verifying the hyperbolic decline “b” factor to be used for production decline analysis; we normally understand the mathematical meaning, but very rarely spend the time understanding the physical meaning and the consequences of using the wrong value. Once the “b” factor is defined, the proper documentation must be filed for each reserve record and the focus becomes the economic analysis of those reserves which is critical for future development especially in a very volatile economy in which prices are fluctuating a lot.

The production of natural gas from shales traces back to the first well drilled in New York in 1821. Over the past 25 years, access to this resource has grown. Recent advancements in drilling and completion technology has enhanced well production rates and production from shales has increased to where it currently supplies 20% of the gas produced by all gas wells in the United States. Well performance data from these shale plays has been compiled and analyzed to develop insight into these tight reservoirs. These results are compared and contrasted to determine similarities and differences among the plays. Comparisons with classical gas reservoirs and tight gas reservoirs are made to provide additional insight.

Many times lowering surface pressure results in production increases on tight gas wells but how does that increase hold up in the long run and what is the rest of the story on wells that originally did not show increases? A previous paper (SPE 90550) detailed results at the start of a long range program to install wellhead compression (WHC) in ConocoPhillips' Lobo Field in South Texas. Updated data showing the long term results over seven years on the original 21 wells are presented as well as results and lessons learned from over 40 additional installations. Based on these experiences, a general approach toward choosing candidates and operating wellhead compression on tight gas wells is proposed.

Traditional shale formations are presently being produced via horizontal well completions. These horizontal wells consist of numerous selectively stimulated stages containing as many as 20 stages spread out across 2000 ft to 9000 ft interval. The well completions have been stimulated using low technology methods such as high volume water / slick water & sand. The initial production of the well requires a short period of flowback of the injected load water prior to the wells being kicked off with hydrocarbon production. The load water flowback can range from as little as 2% load return as high as 70% returns. Since these types of formations are far from being homogeneous, these horizontal laterals can intersect existing natural fractures or faults in the formation or an aggressive stimulation could induce fractures into existing natural fracture or faulting network. This paper will showcase horizontal well production logging measurements ideal for this flowing environment in order to deliver a high confidence, representative flow profile. In addition, deployment techniques & the logging challenges will be discussed to establish the best possible representative flowing environment for measuring these types of well completions.

Gas in place/reserves estimation in unconventional (low/ultra-low permeability) reservoirs has become a topic of increased interest as more of these resources are being developed domestically and internationally. Production data from these unconventional gas reservoirs exhibit extended periods of transient/transition flow behavior that often lead to the overestimation of gas in place/reserves with the use of simple rate-time extrapolation techniques. In this work we show that the analysis of production data (particularly rate-time data) before the onset of boundary dominated flow for these unconventional gas reservoirs leads to significant overestimation of gas in place/reserves. Consequently, we introduce the concept of "continuous estimation of ultimate recovery" (or "continuous EUR ") where estimation of reserves from a single gas well is performed in a dynamic fashion — in other words we continuously estimate the reserves for selected time intervals throughout the producing life of the well. We have applied the "continuous EUR " method by using simple rate-time relations such as the Arps' "hyperbolic" rate decline relation and the power-law exponential rate decline relation along with the straight line extrapolation technique, which provides a lower limit for EUR . We present the application of the "continuous EUR " method with a simulated tight gas data set and four (tight gas) field data sets. Our analyses show that the distinction in the flow behavior is more evident and the uncertainty in reserves estimation decreases significantly when reserves are evaluated continuously.