Hong, Aojie (National IOR Centre of Norway and University of Stavanger) | Bratvold, Reidar B. (National IOR Centre of Norway and University of Stavanger) | Lake, Larry W. (University of Texas at Austin) | Ruiz Maraggi, Leopoldo M. (University of Texas at Austin)
Aojie Hong and Reidar B. Bratvold, National IOR Centre of Norway and University of Stavanger, and Larry W. Lake and Leopoldo M. Ruiz Maraggi, University of Texas at Austin Summary Decline-curve analysis (DCA) for unconventional plays requires a model that can capture the characteristics of different flow regimes. Thus, various models have been proposed. Traditionally, in probabilistic DCA, an analyst chooses a single model that is believed to best fit the data. However, several models might fit the data almost equally well, and the one that best fits the data might not best represent the flow characteristics. Therefore, uncertainty remains regarding which is the "best" model. This work aims to integrate model uncertainty in probabilistic DCA for unconventional plays. Instead of identifying a single "best" model, we propose to regard any model as potentially good, with goodness characterized by a probability. The probability of a model being good is interpreted as a measure of the relative truthfulness of this model compared with the other models. This probability is subsequently used to weight the model forecast. Bayes' law is used to assess the model probabilities for given data. Multiple samples of the model-parameter values are obtained using maximum likelihood estimation (MLE) with Monte Carlo simulation. Thus, the unique probabilistic forecasts of each individual model are aggregated into a single probabilistic forecast, which incorporates model uncertainty along with the intrinsic uncertainty (i.e., the measurement errors) in the given data. We demonstrate and conclude that using the proposed approach can mitigate over/underestimates resulting from using a single decline-curve model for forecasting. The proposed approach performs well in propagating model uncertainty to uncertainty in production forecasting; that is, we determine a forecast that represents uncertainty given multiple possible models conditioned to the data. The field data show that no one model is the most probable to be good for all wells. The novelties of this work are that probability is used to describe the goodness of a model; a Bayesian approach is used to integrate the model uncertainty in probabilistic DCA; the approach is applied to actual field data to identify the most-probable model given the data; and we demonstrate the value of using this approach to consider multiple models in probabilistic DCA for unconventional plays. Introduction Although numerical techniques for forecasting hydrocarbon production have developed rapidly over the past decades, DCA remains an industry-accepted method and is used extensively in the oil and gas industry. Decline-curve models are very computationally attractive because only production data, which can be easily acquired, are required for determining a few parameter values through history matching.
Hong, Aojie (University of Stavanger and The National IOR Centre of Norway) | Bratvold, Reidar B. (University of Stavanger and The National IOR Centre of Norway) | Lake, Larry W. (The University of Texas at Austin)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Decline curve analysis (DCA) for unconventional plays requires a model that can capture the characteristics of different flow regimes. Thus, various models have been proposed. Traditionally, in probabilistic DCA, an analyst chooses a single model that he/she believes best fits the data. However, several models might fit the data almost equally well and the one that best fits the data might not best represent the flow characteristics. Therefore, uncertainty in which is the "best" model remains. This work aims to integrate model uncertainty in probabilistic DCA for unconventional plays. Instead of identifying a single "best" model, we propose to regard any model as potentially good, where goodness is characterized by a probability.
Tang, Yula (Chevron North America Exploration & Production) | Liang, Baosheng (Chevron North America Exploration & Production) | Larsen, Leif (KAPPA Engineering and University in Stavanger) | Luk, Hannah (Chevron North America Exploration & Production)
A reliable and low cost water supply source is critical for Permian Basin unconventional reservoir development. The Santa Rosa formation, a sandstone aquifer imbedded in the Dockum Group in the Midland Basin, and the Rustler formation, a mixture of dolomite and limestone in the Delaware Basin, are two important aquifers that many operators heavily rely on for brackish water sources. Aquifer volume and deliverability, as a function of water well count, are two key parameters challenging a viable water supply strategy.
Thus, a multi-scale workflow simulating aquifer size and production prediction was developed to investigate these parameters and assess potential water supply volumes. The workflow includes an upscaling of the model in stages starting with a single-well model based on actual well test measurements and then expands the model to cover the local development field that encompasses multiple water supply well test locations. Finally, the model is upscaled to the entire development region (called the corridor model). Such detailed information can be further rolled up to update the aquifer model in the basin.
Downhole pressure gauges and surface flow meters are currently installed in 15 Santa Rosa water wells in the Midland Basin and one Rustler water well in the Delaware Basin to periodically update and refine the models. For each well, an individual pressure transient analysis provides assessments of well productivity, boundary conditions, well interference, and wellbore damage. For the area of interest in the Midland Basin, the multi-well model provides information on aquifer boundaries, conductivity, and structural connectivity. Then, a reservoir simulation model is generated from multi-well tests to assess aquifer deliverability for hydraulic fracturing water demands in different drilling schedules and identify future in-fill well locations based on aquifer continuity, conductivity, and company leasehold. When new wells are added, pressure and production information will be used to update the model.
The Bob L. Herd Department of Petroleum Engineering at Texas Tech University has significantly revised the curriculum for the senior year. In response to industry, Texas Tech’s petroleum industry advisory board, senior exit interviews, and surveys from recent graduates; the faculty have altered the senior course offering. The major concerns expressed centered on providing students with sufficient course work in both Reservoir / Formation Evaluation (RFE) and Drilling / Production Operations (DPO). Adding four additional courses would exceed the reasonable limits of a four year undergraduate BS degree. A 148 hour program would approach conventional MS degrees. The department decided to leverage existing low level master courses to allow seniors to select a RFE or DPO specialty. The goal is more depth and a little less breadth.
During their senior year, students elect to take four RFE or four DPO courses along with the other required senior petroleum courses. This has allowed an interesting dynamic in the two senior semester design sequence. Teams are formed with course background of both RFE and DPO courses. This has also changed the material covered during semesters four, five, and six (sophomore and junior semesters). Students will only have a minimum of coverage in either RFE or DPO courses in semester four-six. During these three semesters, the department significantly ramped up the petroleum material covered. Departments of Geology, Energy Commerce, and Industrial Engineering have provided petroleum related course improvements to further enhance the student outcomes.
The department has completed its first year of the new curriculum, and plans to share the results at the next SPE Annual meeting. These changes have been tracked using ABET methods to assess and improve the program.
The vision was to enhance undergraduate student understanding of the theory and equations taught by building concepts of procedure and construction. Designing procedures for oil field operations and evaluation is key to developing critical thinking. Concepts of largeness of scale of the industry, timing and logistics, and the ability to “critically think” about the reservoirs and fluids; all under conditions that are not observeable in their downhole “native” state are extremely difficult to convey through equations and computer program “black boxes.” The faculty and industry advisory board noted a gradual movement of recent graduates to rely on “plug and chug” putting values in equations and computer black boxes prior to determining whether the numbers input are correct or accurate. Students were relying too much on the computer answer without ensuring the values represented a reasonable result. They often didn’t question the magnitude or the significant figures (accuracy) of their answers. In addition to understanding magnitude and accuracy, students are taught the uncertainity that petroleum engineers must deal with is a critical distinction of the profession.
Laboratory and borehole measurements of shale properties may be unreliable because of modification during or after drilling or coring. The borehole gravimeter is an ideal tool for measuring the bulk density of thick shale units because of its great depth of investigation and negligible sensitivity to shale in the vicinity of the borehole, which may have been modified in drilling. By contrast, the scatter gamma ray density log has an extremely shallow depth of investigation and its response may be dominated by modified shale surrounding a borehole. A comparison of bulk densities measured by these two methods in both sands and shales was made in three U.S. gulf coast wells. In all three wells the two methods yielded comparable densities for the sands. But in two wells, which were drilled with fresh muds, the density log yielded shale bulk densities significantly less than those shown by the borehole gravimeter. These data indicate that shale adjacent to the borehole in these two wells had been modified by drilling and the modified shale densities had been reduced significantly. In the well drilled with a saline mud, bulk densities from the two methods were in close agreement in both sands and shales, which indicates that shales adjacent to the borehole in this well were not modified significantly.
High-pressure shales are particularly susceptible to modification during drilling since they are relatively permeabble and soft. Sometimes they even flow. Density log data in high-pressure shales are unreliable due to probable shale modification. Unfortunately, we have no borehole gravimeter data in high. pressure shales and, therefore, no reliable measurements of bulk densities in their natural state. The best data available for studying high-pressure shales are some neutron lifetime logs. The effective depth of investigation of the neutron lifetime log is considerably greater than that of the scatter gamma ray density log.1,2 Therefore, neutron lifetime log measurements should be affected much less by any modified shale near the borehole than would measurements made with a density log.
Neutron lifetime logs show a progressive decrease in macroscopic neutron capture cross section with increasing depth for U.S. gulf coast shales with normal pore pressures. This decrease in neutron capture cross section is the result of increased compaction of shales with depth. If high-pressure shales are shales that were not compacted normally with increasing depth of burial, then they should have physical properties comparable with relatively uncompacted shales at much shallower depths of a few thousand feet (1000 to 1500 m). In particular, they should have high neutron capture cross sections as compared with normally pressured shales at slightly shallower depths. However, our logs show neutron capture cross sections for U.S. gulf coast high-pressure shales that range from normal to less than normal for their depths. These data indicate that these high-pressure shales are not shales that were never compacted. The data are consistent with an alternate hypothesis for the generation of high pore pressures in shales.
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This paper was prepared for the 46th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, held in New Orleans, Oct. 3-6, 1971. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
This paper traces the transition of a natural gas field into a major gas storage system" Texas Gas Transmission Corporabon's programs to facilitate the transition programs to facilitate the transition early in the life of the field are shown. A detailed geologic and engineering analysis of the reservoir which has played an important role in the development of storage is also presented. presented. The reservoir in this study is the Midland gas field which is located in Muhlenberg County, Ky. on the southeast flank of the Illinois basin. The field, discovered in Oct., 1962, was converted to a gas storage field on Jan. 1, 1970. It has the potential of being one of the largest gas storage reservoirs in the country and is ideally situated for effective market requirements. The field is approximately 10 miles long and 1-1/2 miles wide, and originally contained 123.6 Bcf of native gas. At the time it was converted to gas storage, 72 Bcf had been produced. The balance was retained for a storage cushion volume.
The Midland gas field produces from the Bethel sandstone of the Lower Chester section of Mississippian age. The rather narrow and elongate physical attitude of the reservoir is the result of a sand fill in a channel cut into the underlying Mississippian carbonates. The maximum thickness of the Bethel Channel fill is in the order of 250 feet.
Diligent collection of reliable basic log and core data, together with the accumulation of an accurate pressure and production history during the productive life of the field is quite important. Because of early planning and persistence, this information has been collected persistence, this information has been collected for very little additional cost. A comparison based on such data is made between original gas-in-place calculations using volumetric methods, steady-state material balance and unsteady-state material balance. This data can also be utilized in additional programs which are needed for future underground storage operations.
Midland gas field is located in Muhlenberg County, Ky. along the southeast flank of the Illinois basin. As shown in Fig. 1, it is located in an area marked by numerous gas and oil producing fields. The discovery well, drilled in Oct., 1962 encountered gas in the Bethel Channel sand of Mississippian age at a depth of approximately 2,100 feet.