Hybrid Modeling In Unconventional Reservoirs To Forecast Estimated Ultimate Recovery

Machine learning models have worked as a robust tool in forecasting and optimization processes for wells in conventional, data-rich reservoirs. In unconventional reservoirs however, given the large ranges of uncertainty, purely data-driven, machine learning models have not yet proven to be repeatable and scalable. In such cases, integrating physics-based reservoir simulation methods along with machine learning techniques can be used as a solution to alleviate these limitations. The objective of this study is to provide an overview along with examples of implementing this integrated approach for the purpose of forecasting Estimated Ultimate Recovery (EUR) in shale reservoirs. This study is solely based on synthetic data. To generate data for one section of a reservoir, a full-physics reservoir simulator has been used. Simulated data from this section is used to train a machine learning model, which provides EUR as the output. Production from another section of the field with a different range of reservoir properties is then forecasted using a physics-based model. Using the earlier trained model, production forecasting for this section of the reservoir is then carried out to illustrate the integrated approach to EUR forecasting for a section of the reservoir that is not data rich. The integrated approach, or hybrid modeling, production forecasting for different sections of the reservoir that were data-starved, are illustrated. Using the physics-based model, the uncertainty in EUR predictions made by the machine learning model has been reduced and a more accurate forecasting has been attained. This method is primarily applicable in reservoirs, such as unconventionals, where one section of the field that has been developed has a substantial amount of data, whereas, the other section of the field will be data starved. The hybrid model was consistently able to forecast EUR at an acceptable level of accuracy, thereby, highlighting the benefits of this type of an integrated approach. This study advances the application of repeatable and scalable hybrid models in unconventional reservoirs and highlights its benefits as compared to using either physics-based or machine-learning based models separately.

Cyclic Gas Injection EOR in Eagle Ford Can Increase Estimated Ultimate Recovery

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200427, “Evaluation of Eagle Ford Cyclic Gas Injection EOR: Field Results and Economics,” by George Grinestaff, SPE, Chris Barden, and Jeff Miller, SPE, Shale IOR, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. Cyclic-gas-injection-based enhanced oil recovery (CGEOR) in the Eagle Ford was begun in late 2012 by EOG Resources and, at the time of writing, has expanded to more than 30 leases by six operators (266 wells). An extensive EOR evaluation was initiated to analyze the results recorded in these leases. The authors write that CGEOR in Eagle Ford volatile oil can yield substantial increases in estimated ultimate recovery (EUR) with robust economics, depending on compressor use and field life. Introduction Eagle Ford Source Rock and Reservoir. The Eagle Ford shale represents some of the world’s richest source rocks. The Upper Cretaceous seafloor received abundant organic debris and preserved it in an anoxic environment. The low permeability of the shale and limestone helped generate hydrocarbons when pore pressure exceeded overburden pressure. The resulting natural fractures provided a means to expel oil, much of it migrating into the overlying Austin Chalk and Tertiary sandstones. The primary target area for produced-gas injection EOR is currently in the volatile oil window between 9,000 and 11,000 ft true vertical depth, which yields oil API gravity of greater than 40. Initial gas/oil ratio (GOR) typically ranges from 1,000 to 3,000 scf/bbl. Eagle Ford EOR History. The first large-scale CGEOR project was implemented in October 2014. Rapid development has occurred since then, but, in the complete paper, the authors present the first commercial EOR projects by EOG Resources because these have the longest CGEOR production history. Recent projects show more-efficient startup, cycling, and higher optimization of gas injection. Therefore, the analysis of EOR in this paper takes a conservative approach of using the first projects because they appear to have lower EOR recovery but more production history. Evaluation Methodology Unconventional EOR Work Flow. Analysis of CGEOR production and results has been completed using production history and reservoir simulation to provide a rigorous evaluation. The authors use a 14-component fracture element model with a very fine grid to predict well GOR, EUR, and reservoir behavior for the compositional process. The element model is then scaled up to mimic the average well for a given pad or lease, and then cycle operations are developed based on CGEOR simulation runs and criteria. Unconventional CGEOR provides a direct response after the first cycle of gas injection; however, the base depletion profile also is important for understanding economics for increased oil production or incremental EOR. A history match of the base depletion is first completed to match an average well at the pad level (approximately one 640-acre section with 10 to 14 wells). The element is then scaled up based on well completion, stimulated rock volume, and EUR for the base depletion.

Getting Your Perforations in a Line Can Mean More-Productive Fracturing

Want more production from a shale well? Consider lining up the perforations. A handful of speakers at the recent SPE Hydraulic Fracturing Technology Conference talked about improved fracturing results with oriented perforating—shooting the holes at the same place in the casing, often the top. This breaks from designs that arranged the holes in a helical pattern with each charge angled 60° from the previous one. “We did see indications we are getting better production from oriented perforating,” said Blake Horton, senior completions engineer for Ovintiv (SPE 204177). Production gains were also reported by ConocoPhillips which compared production from similar wells with and without oriented perforating. The analysis was designed to filter out differences in the geology, drilling, and completions. It concluded the value of the added production far exceeded the $20,000-per-well cost of installing the assembly, including a weight bar to tilt the perforating guns into position. “That’s less than the undiscounted value of 400 barrels of oil. An internal study indicated that ConocoPhillips improved estimated ultimate recovery (EUR) by a minimum of 5% when using high-side-oriented perforating,” said Dave Cramer, senior engineering fellow at ConocoPhillips and an early advocate for the method. “For an initial choked flow rate of 1,000 B/D, the payout on investment is 10 days or less,” he said. Ovintiv declined to provide a number, but Horton said ConocoPhillips’ estimate is within Ovintiv’s range based on similar comparisons of wells with and without oriented perforating. That number is at the low end of the estimates offered in discussions about oriented perforating performance at the conference. Higher estimates are questioned by those who doubt the test results can be sustained when the method is scaled up. What was certain is the number of users is rising and includes names such as Shell and Chevron. “We found that oriented perforating definitely helps to treat all the clusters,” said Jon Snyder, a staff completion engineer for ConocoPhillips who presented the paper, adding, “by oriented perforating we mean that when we are perforating, we aim for the high side of the wellbore” (SPE 204203). When Horton polled the audience at a recent talk, more than half of the respondents said they were using gun systems designed to orient the perforating charges at a target angle. “A year from now, few people will not be doing oriented perforating; the advantages of it are clear,” Cramer said. He has been promoting the idea within the company for years with mixed acceptance.

PENENTUAN INITIAL GAS IN PLACE MENGGUNAKAN METODE MATERIAL BALANCE PADA RESERVOIR I

<p>Reservoir I merupakan reservoir gas yang terletak di daerah Prabumulih, Sumatera Selatan. Tekanan awal sebesar 2.286 psia dan temperatur 240°F. Reservoir I berproduksi sejak Januari 2012 sampai dengan saat ini, dengan total produksi gas (Juni 2019) sebesar 32.178 MMSCF. Dalam pengembangan suatu lapangan gas bumi ada beberapa faktor penting yang harus ditentukan secara akurat, salah satunya dalam menentukan isi awal gas di tempat atau <em>Initial Gas In Place</em> (IGIP), nilai tersebut akan berperan penting dalam keputusan dasar pengembangan dan operasional suatu reservoir.</p><p>Perhitungan <em>Initial Gas In Place</em> (IGIP) dilakukan dengan menggunakan metode <em>material balance</em> P/Z dan simulasi MBAL. Metode <em>material balance</em> dipilih karena memperhitungkan kesetimbangan massa dan tenaga dorong reservoir, dan data yang diperlukan lebih lengkap dibandingkan metode yang lain. Pada perhitungan dengan menggunakan metode<em> material balance </em>P/Z,<em> Initial Gas In Place</em> yang didapat sebesar 60.915,49 MMSCF, dan nilai perhitungan menggunakan software MBAL sebesar 60.604,5 MMSCF. Jenis tenaga dorong reservoir ini adalah <em>depletion drive</em>, yang ditentukan dari plot P/Z vs Gp yang menghasilkan garis lurus. Berdasarkan nilai tekanan <em>abandon</em> sebesar 300 psia didapatkan nilai <em>estimated ultimate recovery</em> sebesar 53.700 MMSCF, dengan nilai <em>recovery factor </em>88,15% dan sisa gas yang dapat diproduksikan (<em>remaining reserves</em>) sebesar 21.522 MMSCF.</p>