This paper presents a methodology for quantifying uncertainty in production forecasts using Logistic Growth Analysis (LGA) and time series modeling. The applicability of the proposed method is tested by history matching production data and providing uncertainty bounds for forecasts from eight Barnett Shale counties.
In the methodology presented, the trend in the production data was determined using two different non-linear regression schemes. Predicted trends were subtracted from the actual production data to generate two sets of stationary residual time series. Time series analysis techniques (Auto Regressive Moving Average models) were thereafter used to model and forecast residuals. These residual forecasts were incorporated with trend forecasts to generate our final 80% CI.
To check reliability of the proposed method, we tested it on 100 gas wells with at least 100 months of available production history. The CIs generated covered true production 84% and 92% of the time when 40 and 60 months of production data were used for history matching respectively. An auto-regressive model of lag 1 was found to best fit residual time series in each case.
The proposed methodology is an efficient way to generate production forecasts and to reliably estimate the uncertainty. The method is computationally inexpensive and easy to implement. The utility of the procedure presented is not limited to gas wells and can be applied to any type of well or group of related wells.
A major challenge faced by the oil and gas industry is estimation of reserves for unconventional reservoirs. Traditional methods used to predict reserves for conventional wells are inappropriate for unconventional wells.
Construction of "Type Well" profiles is widely considered to be a useful tool for production forecasting, especially in presentations to investors. Type wells play an important role in estimating the EUR for a particular new well and for undrilled wells. They are responsible for guiding forecasts in wells expected to have similar behavior and characteristics. The conventional approach is to determine the arithmetic average of production during a given month from different wells in a reservoir of interest to create a type well. This methodology is deeply flawed, however, and results in significantly different estimates by different evaluators. The conventional approach may lead to either overestimates or underestimates (usually overestimates) of future production from a particular well or reservoir. This paper discusses the problem in depth and recommends possible ways in which type well construction can be made more realistic. In order to ensure more accurate forecasts from an individual well, a new approach is proposed. A detailed procedure to identify and remove outliers from production data is implemented in the workflow. We analyzed production data from Barnett shale reservoir and incorporated our findings in our proposed method to create type wells for a wide variety of reservoir types, with variations in both rock and fluid characteristics. Our analysis also includes suggestions for applying type well production profiles generated in one portion of a given reservoir to another area in the reservoir with different geological characteristics, notably permeability.
This paper reports a critical review of the operational principles and the most important completions techniques used in hydraulic fracturing in the U.S.A. and investigate whether they are applicable to the Posedonia geological and surface environment conditions in Europe. It is found that both cemented liner and open-hole with external packers completions wells have been used in shale gas developments. Plug and Perf and continuous pumping multi-stage hydraulic fracturing methods were respectively used. Low viscosity fracturing fluids are preferred to increase fracture complexity in brittle shale. Large stimulated reservoir volume by increase fracture density effective fracture half-lengths and use of proppant techniques to increase fracture conductivity. It is found that the Posedonia shale is comparable to several U.S.A. shale pays in terms of geological and petrophysical attributes (porosity, permeability, thickness, gas, oil and water content water). Therefore, we expect the multi-stage fracturing techniques developed in the U.S.A. to be largely applicable for the Posedonia shale. However, larger softness and greater depths of the Posedonia shale make more viscous fracturing fluids and fewer but much longer horizontal wells inevitable. Provided such longer horizontal wells are used, production rates similar to those reached in U.S.A. shale gas wells could be achievable.
Natural gas production from unconventional gas reservoirs in North America rely on the technologies of horizontal drilling and multi-stage hydraulic fracturing. The cased and cemented completion technique, Plug-and-perf (P-n-P), has been utilized as a traditional completion in horizontal wells for many years. However, the openhole completion technique, Open Hole Sleeve Multi-stage System (OHMS), has gained favor in the past decade, because of its cost and time efficiencies. Production comparisons between these two completion methods remain a controversial subject, with ongoing debate regarding which method yields more gas production.
Historical studies compare production indicators, typically from a limited set of sample wells. These historical studies indicate either insignificant differences between the two completion methods, or that OHMS systems significantly outperform P-n-P. However, these historical studies are limited in a number of ways.
A computational fluid dynamics model (CFD) has been developed to compare P-n-P completions with OHMS for horizontal, multi-stage fractured wells. The numerical model uses a 6-inch borehole draining a tight gas reservoir (0.01 mD), under steady state flow with no formation damage. The P-n-P completion assumes 0.22 in., 180o phased perforations connecting to a planar fracture penetrating the height of the reservoir. The OHMS completion assumes sandface flow, and no orifice effect from the sleeve openings. Both completions assume the planar fracture intersects at the center of the reservoir model.
The results of the CFD analyses compare the productivity index ratio (J/Jo) verses dimensionless fracture conductivity (Cfd) for each completion over a range of fracture conductivity (kfw) obtained from commercial proppant data. Parametric studies were performed varying propped fracture width, fracture half-length and vertical to horizontal permeability ratio (kv/kh), to investigate the effects of these parameters on the completion comparison.
This paper presents the results of the numerical modeling and compares productivity index results to historical, production-based studies of the P-n-P and OHMS completions in horizontal, multi-stage fractured wells. This work verifies a slight production advantage in OHMS systems versus P-n-P completions used in horizontal wells today. The work is significant because few, if any, numerical models have been developed to study and compare performance of these completions.
Hayes, Thomas D. (Gas Technology Institute) | Halldorson, Brent (Fountain Quail Water Management) | Horner, Patrick H. (Fountain Quail Water Management) | Ewing, John Jay R. (Devon Energy Corporation) | Werline, James R. (Devon Energy Corporation) | Severin, Blaine F. (Environmental Process Dynamics, Inc.)
Used extensively by the food, chemical, and pharmaceutical industries, the mechanical-vapor-recompression (MVR) process is viewed as a reliable method for recovering demineralized water from concentrated brines. Devon Energy has supported the operation of an advanced MVR system at a north-central Texas (Barnett shale region) treatment facility. At this facility, pretreatment included caustic addition and clarification for total-suspended-solids and iron control. Pretreated shale-gas flowback water was then sent to three MVR units, each rated at 2,000–2500 B/D (318–398 m3/d). Data were collected during a 60-day period in the summer of 2010. Distilled-water recovery volume averaged 72.5% of the influent water to the MVR units. The influent total dissolved solids (TDS) fed to the MVR units averaged just under 50 000 mg/L. More than 99% of the TDS were captured in the concentrate stream. The fate of multivalent cations; total petroleum hydrocarbons (TPH); and benzene, toluene, ethylbenzene and xylenes (BTEX) throughout the treatment system was determined. Most of the iron and TPH removal (90 and 84%, respectively) occurred during pretreatment. The total removal of iron, magnesium, calcium, barium, and boron from the distillate exceeded 99%. BTEX removal from the distillate exceeded 95%. Electric power at the facility was provided by two natural-gas generators, and compressors associated with the MVR units were driven by natural-gas-fueled internal-combustion engines. Energy requirements at the entire treatment facility were tracked daily by total natural-gas use. Best-fit correlations between treated water and distillate production vs. total plant use of natural gas indicated that there was a base power load throughout the facility of approximately 120 to 140 Mscf/D (3400 to 3960 m3/d) of gas. Approximately 48 scf natural gas/bbl influent water treated (270 m3/m3 influent) or 60.5 scf/bbl distillate produced (340 m3/m3 distillate) was required; this represents an energy cost of less than USD 0.25/bbl treated (USD 0.04/m3 treated) and approximately USD 0.30/bbl of distillate product generated (USD 0.048/m3 distillate), assuming a natural-gas cost of USD 5/million Btu (USD 4.72/GJ). Performance in terms of water recovery and product-water quality was stable throughout the 60-day test.
Development of unconventional reservoirs continues to expand in North America and has gained interest worldwide. The first unconventional play to be rapidly developed is the Barnett Shale located in North Central Texas. As of July 2012, the Barnett Shale had more than 13,000 multi-staged fractured horizontal wells (MFHW) with approximately 2,500 of these wells with over five-plus years of production history. In addition to these MFHW, there are approximately 3,000 vertical wells in the Barnett Shale.
Well spacing is a key value driver for field development and needs to be addressed early in the appraisal process. Interpretation of early production analysis from MFHW can provide many insights into the reservoir and fracture characteristics of these wells. However, these interpretations are non-unique until end of linear flow (ELF) is reached. This study used public production data that lacks wellhead flowing pressures. For this study the wells that did see end of linear flow did so in a time period where flowing pressures are expected to be relatively constant and therefore having measured pressures was not deemed necessary. Reservoir permeability, fracture half-length, and original-gas-in-place of the area contacted by the created hydraulic fracture network can be determined once end of linear flow is reached. Once fracture half-length and permeability have been determined, the appropriate well spacing can be estimated using simulation and economics.
A comprehensive review of approximately 2,500 MFHW using public data within two Northern counties of the Barnett Shale found more than 100 wells where end of linear flow could be clearly observed in production characteristics. With the end of linear flow determined for these wells, estimates of permeability and fracture half-length were determined. A single well simulation study feeding an economic evaluation was then used to study well spacing and yield suggested optimum development spacing. This paper will review all of this work, the results and conclusions, and provide observations of some of the trends.
Unconventional play development continues to expand quickly around the globe. The first unconventional play to be rapidly developed has been the Barnett Shale in North Central Texas. As of July 2012, the Barnett Shale has more than 13,000 multi-fractured horizontal wells (MFHW) with approximately 2,500 being five years or older. This gives the Barnett Shale a significant production database from which to perform production analysis.
Well spacing is a key value driver for field development and needs to be addressed early in the appraisal process. The extensive public production database was used to gain insights as to appropriate well spacing in two counties of the Barnett Shale, Denton and Wise. This paper demonstrates a workflow to understand appropriate spacing for future development based on infill production performance. Initial peak production and one-year cumulative gas production from infill and non-infill wells are used as key performance indexes. An important assumption of this work is that well spacing should be as close as possible where infill well results are as good as non-infill wells. When the infill well performance is poorer than the non-infill wells, the spacing is too close.
Forty MFHW spacing pilots were identified and analyzed, with 34 of these pilots meeting criteria for use in the study. This paper will review the workflow, the results, provide a recommended spacing based upon the performance data and also highlight other factors that may need to be considered. Currently, this paper is believed to be the first to utilize field performance in a simple and objective yet robust manner to generate a recommended spacing for a given area.
A new low-concentration, low-viscosity delayed-crosslink polymer gel system was developed for water shutoff in small aperture features in higher temperature oil and gas reservoirs. The gel employs hydrolyzed polyacrylamide (HPAM) and Polyethyleneimine (PEI) crosslinker. Addition of 2-Acrylamido-2-methylpropane sulfonic acid (AMPS) as a crosslink delay agent increases the gelation time by several days at temperatures well above 100 °C. Resulting gels were significantly stronger than those prepared with chromium acetate crosslinker at the same polymer concentrations. The HPAM-PEI-AMPS system consists of inexpensive components which are widely used in the oilfield. The system was studied for effects of concentration of polymer and crosslinker, PEI:AMPS ratio, pH and cation concentration on gelation time and gel strength. Gelant solutions prepared with high molecular weight HPAM exhibit a longer delay in gelation at temperatures well above 100 °C. The ability to form strong gel at lower polymer concentrations, with a considerable delay in gelation time, offers the opportunity to extend application of flowing gels to water shutoff in fractured reservoirs where extrusion pressures are too great for more conventional flowing gels that are partially crosslinked during placement. The system is especially promising for deeper, hotter formations where rapid pressure buildup or gel instability prevents the use of current flowing gel systems. The gelant can be pumped at low pressures due to the low concentration of polymer and the delayed gelation to effectively seal problem water zones thereby reducing operational costs and increasing recovery. By impeding water production, the gel system developed here can be used to delay excess water influx and thus premature abandonment (or installation of expensive lift equipment), thereby extending the life and reserves of unconventional oil and gas wells.
According to the Railroad Commission of Texas (RRC), the Texas Permian Basin rig count climbed from 129 in 2005 to 355 in 2011, sustaining a dip to 103 in 2009 with no drop in crude oil production. Total Permian Basin rig count climbed to 500 in May 2012, according to a US Energy Information Administration (EIA) report, and as of late December 2012, stood at 454. The number of drilling permits issued by the RRC has exhibited a similar rise, from 4,459 in 2005, with a downdip to 3,369 in 2009 and then a steep climb to 9,347 in 2011. The price of natural gas remains depressed in the US, largely because of a glut due to a rush to exploit very tight gas resources in shale plays such as the Marcellus, Eagle Ford, Barnett, Haynesville-Bossier, Fayetteville, Woodford, and Bakken. A trend over the past few years has therefore been building towards a focus on liquids-rich plays.