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.
This study provides horizontal pipe pressure drop and liquid holdup measurements for three-phase flow of sand, viscous oil and gas with a focus on slug flow. We developed a correlation for predicting the liquid holdup and dimensionless pressure gradient in the presence of solids during slug flow.
A multiphase flow loop facility with 1.5in (0.0381m) Schedule 80 PVC pipes was designed and constructed to flow viscous oils ranging from 150 to 218cP (0.15 to 0.218Pa-s). A progressive cavity pump (PCP) was used to pump the complex mixture from a double walled steel tank. Compressed air was used as the gas phase and 0 to 1% of 180μm diameter sand by weight was added to the flow. The facility had a clear test section for flow pattern visualization and photography. Equipment issues and operational difficulties in the setup were identified during initial tests and rectified. Oil and gas flow rates, differential and absolute pressures, liquid holdup (both with and without the presence of solids), and fluid temperatures were measured and flow pattern observations were photographed. Gas and viscous oil superficial velocities ranged from 0.5 to 10m/s and from 0.1 to 1m/s respectively.
We validated the setup by comparing actual single phase liquid pressure drop measurements to an analytical expression for computing the pressure drop during single phase viscous oil flow. Sand was introduced into the system thereafter. We found that the presence of sand did not shift the flow pattern boundaries appreciably and slug flow was the most commonly encountered flow pattern. As such, we focused on the slug flow region. Slow motion photo and videography revealed that the presence of sand disrupted the sharp head and tail profiles in the liquid slug body. Regression analysis using the observed data revealed that for slug flow of viscous oil and gas, the most important dimensionless groups affecting both the holdup and the dimensionless pressure gradient are the fluid velocity numbers and the Froude number. For three-phase slug flow of sand, viscous oil and gas, the most important dimensionless groups for affecting holdup in the presence of solids are the fluid velocity, Reynolds, and Froude numbers in addition to the pipe diameter number and the sand fraction in the flow stream. For dimensionless pressure gradient, the most important dimensionless groups are the fluid velocity numbers, the Reynolds/Froude numbers and the input liquid fraction.
Slug unit length was also measured and the data was matched with an existing correlation. We also detailed the effect of sand on pattern behavior in each of the commonly observed horizontal pipe multiphase flow patterns using videography.
To the best of our knowledge, this is the first recorded attempt at measuring pressure drop and liquid holdup in the presence of solids for the horizontal multiphase flow of sand, viscous oil and gas. This work provides laboratory data/models that can support the characterization of the pressure drop and flow patterns experienced in horizontal wells completed using the Cold Heavy Oil Production with Sand (CHOPS) process and other viscous oil producing wells.
The paper presents laboratory, and field characterization studies of the weak floor strata associated with the Illinois No. 6 and No. 5 coal seams. The research included: 1) Laboratory measurement of engineering index properties; clay mineral composition, and strength-deformation properties; 2) Field measurement of shear strength properties using a Rock Borehole Shear Tester (RBST); 3) Field measurement of Ultimate Bearing Capacity (UBC) and deformabilityusing plate loading tests; and 4) Correlation between laboratory and field determined properties. Results show that: 1) Inherent moisture content (MC), Atterberg Limits (AL), indirect tensile strength, and lithologic description of weak floor strata are most important to describe weak floor strata behavior in the field; 2) Most claystones associated with the immediate floor strata may be characterized as clays of low to medium plasticity; 3) A minimum square plate size of 20-cm is recommended for conducting plate loading tests; and 4) Plate UBC and deformation modulus in the field can be estimated from the MC and AL of weak floor strata down to a depth of 30-cm below the coal seam.
The flow behavior in nano-darcy shales neighbored by high conductivity induced natural fractures violates the assumptions behind Arps' decline models that have been successfully used in conventional reservoirs for decades. Current decline curve analysis models such as Logistic Growth Analyses, Power Law Exponential and Duong's model attempt to overcome the limitations of Arps' model. This study compares the capability of these models to match the past production of hundred shale oil wells from the Eagle Ford and investigate how the choice of residual function affects the estimate of model parameters and subsequently the well life, pressure depletion and ultimate recovery. Using the proposed residual functions increased the tendency of deterministic models to have bounded estimates of reserves. Results regarding well performance, EUR, drainage area and pressure depletion are obtained quickly and show realistic distributions supported by production hindcasts and commercial reservoir simulators. Overall, the PLE and Arps' hyperbolic models predicted the lowest/pessimistic and highest/optimistic remaining life/reserves respectively. The newly proposed residual functions were thereafter used with the Arps' hyperbolic and LGA models. We found that the use of rate-time residual functions increased the likelihood of the value of hyperbolic exponent being less than 1 by 87.5%.
A new workflow that uses the strain derived from geomechanical modeling of hydraulic fractures interacting with natural fractures is applied to an Eagle Ford well. The derived strain map is used to estimate the asymmetric half lengths that are input in any frac design software able to incorporate this new information. The simplistic symmetric and bi-wing design is revised by adjusting the leakoff coefficient, injection rate, and proppant concentration resulting in asymmetric half lengths that do not exceed the lengths of those provided by the strain map. Once the half lengths and orientation from the frac design match those provided by geomechanical simulation, the propped length and other key results provided by the frac design software may be used to optimize the well's completion. This process could be used iteratively to optimize desired metrics and could also be used to improve reservoir simulation.
The derived strain map may be propagated in the stimulated geomechanical layer to form a strain volume which may in turn be used to estimate the stimulated permeability. In this paper, we used a radial function to relate the stimulated permeability to the strain within the maximum half lengths provided by the strain map. Two calibration constants are needed in the radial functions and could be estimated by history matching or pressure transient analysis. An adaptive Local Grid Refinement (LGR) and variable stimulated permeability provide a realistic representation of the stimulated reservoir volume (SRV). After history matching, the resulting pressure distribution allows an accurate selection of refrac or new well candidates, for optimizing well spacing, and for estimating an accurate EUR.
Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Arctic Technology Conference held in Houston, Texas, USA, 10-12 February 2014. This paper was selected for presentation by an ATC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract In Alaska, unmanned aircraft systems (UAS) have garnered much attention, largely due to ongoing research at the University of Alaska Fairbanks (UAF).
In this paper the authors report the vertical bending properties of a test chilled gas pipeline and the countermeasures of the bending. A full-scale field experiment of the chilled gas pipeline system was conducted in Fairbanks, Alaska from 1999 to 2005. The length of the test pipeline was 105m and the diameter was 0.9m. The circulated chilled air was –10°C. One-third of the pipeline was buried in frozen ground and the rest of it was placed in talik. At the end of July 2003, circulation of the chilled air ceased, however, monitoring of the thaw settlement-related properties of the test pipeline continued until the middle of April 2005. The following results were presented at the 2nd ATC: 1) As the frost-bulb around the pipeline in talik section formed, the test pipeline in the talik section moved upward, resulting in bending of the pipeline at the boundary. 2) In summers, frozen overburden soil of the pipeline became thinner due to thawing of active layer above. The pipeline buried in frozen section moved upward abruptly, fracturing the thinning frozen overburden ground. 3) The phenomenon mentioned in 2) occurred in successive summers, and the pipeline uplift in frozensection continued. 4) In relation with 1), the upward movement in talik section was confirmed by frost heaving of the pipe foundation. In this report the bending behavior of the test pipeline is described and the several methods to deal with the bending are proposed.
Hendricks, S. (Alfred Wegener Institute) | Hunkeler, P. (Alfred Wegener Institute) | Krumpen, T. (Alfred Wegener Institute) | Rabenstein, L. (Alfred Wegener Institute) | Eicken, H. (University of Alaska) | Mahoney, A. (University of Alaska)
This paper presents the findings of airborne sea-ice thickness measurements in the Beaufort Sea near Barrow, Alaska. We discuss the applicability of airborne electromagnetic (AEM) induction for ice thickness monitoring in near coastal areas. All measurements were done within the NSF funded Seasonal Ice Zone Observation Network (SIZONet) which organizes airborne sea ice thickness surveys every spring since 2007. The key finding is, that thickness of grounded ice features in shallow water regions can be mapped with the AEM method. This is of particular interest, since other established methods, like upward looking sonar, can not be applied for potentially hazardous sea-ice features in shallow water regions.