Data mining for production optimization in unconventional reservoirs brings together data from multiple sources with varying levels of aggregation, detail, and quality. The objective of this study was to compare and review the relative utility of several univariate and multivariate statistical and machine-learning methods in predicting the production quality of Permian Basin Wolfcamp shale wells. Methods considered were standard univariate and multivariate linear regression and the advanced machine-learning techniques support vector machine, random forests, and boosted regression trees. In the last few decades, because of the diminishing availability of conventional oil reserves, unconventional reservoirs are fast becoming the mainstream source of energy resources. In the meantime, with technology advances in data collection, storage, and processing, the oil and gas industry, along with every other technical industry, is experiencing an era of data explosion.
Using horizontal wells for primary production of heavy oil reservoirs is common in Canada but it is less frequent to employ them for waterflood. As a result, very few papers have been published on this topic. Similarly, numerous publications are available on the use of conventional forecasting methods to evaluate waterflood performances, but very few if any have focused on waterfloods with horizontal wells in heavy oil reservoirs. This is what this paper proposes to do.
The production performances of over twenty horizontal wells from five Canadian heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. Conventional waterflood forecasting methods such as Arps, Yang and logarithm of Water-Oil Ratio (WOR) vs. Cumulative oil production were used and compared. However, the focus of the paper is not only the comparison of the various forecasting methods but also the evaluation of the performances of horizontal well waterfloods in these high oil viscosities.
The Arps method appears difficult to use, especially when there are strong variations in injection rates. By comparison, the Yang and the WOR vs. Cumulative production methods appear more stable. The forecast in cumulative production can vary widely between these methods. Ultimate recovery is expected to vary from a few percent OOIP to over 20%OOIP.
This paper will present the performances of several horizontal waterfloods in heavy oil reservoirs in Canada and compare several waterflood analysis methods. Very few if any paper has been published on this topic thus the information provided will be of interest to engineers who are considering using horizontal wells for waterflood as a follow-up to primary production in heavy oil reservoirs.
Baharuddin, Saira Bannu (Petroliam Nasional Berhad, PETRONAS) | Khair, Hani Abul (Petroliam Nasional Berhad, PETRONAS) | Bekti, Reza Amarullah (CGG) | Ali, Amita Mohd (Petroliam Nasional Berhad, PETRONAS) | Kantaatmadja, Budi (Petroliam Nasional Berhad, PETRONAS) | Som, Mohd Rapi Muhammad (Petroliam Nasional Berhad, PETRONAS) | Sedaralit, Faizal (Petroliam Nasional Berhad, PETRONAS)
Bioturbated zones are frequently bypassed by oil and gas operating companies during perforation due to the perception that they are nonproductive. We analysed data from wells in four fields in the Sarawak Basin, Malaysia, for selected bioturbated zones. The study included thin section, probe-permeameter, petrophysical, and routine core analysis. A bioturbation index classification scheme was established to allow semi-quantitative ranking for each foot of core. In the current study, we introduce a simulation script to predict lithofacies types at well locations based on input from bioturbation intensity algorithm (Ali et al., 2016), this script can be used for application on shallow marine field within Malaysia. We also used post stack seismic inversion for acoustic impedance and it proved to be a key approach to enhance the ability of predicting rock properties between wells. We generated a seismic derived lithofacies which provided the best estimate of lithofacies distribution between wells even though a well derived lithofacies had higher resolution. We calculated STOIIP using input from seismic lithofacies and porosity, and the results showed more accurate estimate of hydrocarbon in place compared with statistical approaches. Thus, the current seismic lithofacies methodology can be used for static model building and STOIIP calculation in shallow marine environments.
Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).
The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.
The economic trade-off between overcapitalization and ineffective hydrocarbon recovery has forced operators in shale plays to focus their efforts on understanding optimal wellbore spacing, both in the vertical and horizontal sense. Matrix permeability has a significant impact on the reservoir modeling results that drive many of these development decisions. Despite incorporating modern crushed-rock pressure-decay permeability datasets, well production is commonly degraded at wellbore spacing schemes much wider than the models indicate. The overstatement of permeability is likely due to experimentally derived flow-regime effects inherent to the analysis. Large helium gas molecules at low pressures are used in crushed-rock permeability experiments, which allow individual gas molecules to be quite far apart (they have a large mean free path, λ). Since shale pores are often smaller than λ, it is more likely a gas molecule will hit a pore wall than another gas molecule. This creates flow-regime effects, which tend to overstate permeability up to several orders of magnitude. To test this hypothesis, several crushed-rock samples from the Devonian Duvernay and Jurassic Nordegg Formations in the Kaybob area in the Western Canadian Sedimentary Basin (WCSB), as well as the Late Cretaceous Eagle Ford Formation in South Texas were analyzed with a pressure-decay apparatus at various λs. This was accomplished by manipulating the gas molecule used and the equilibrium pressure of the test. Although significant differences were observed, conventional approaches for correcting flow-regime effects, including slip and double-slip plots, were not successful in deriving the true (intrinsic) matrix permeability. A new technique, referred to as the λ plot, enables a reasonable derivation of flow-regime corrected permeability and effective pore size for all the samples. This permeability, k1λ, corrects the λ to a typical plug permeability experiment value of 1 nm, which we believe is quite close to the true (intrinsic) permeability. The results indicate that the median matrix permeability for all samples is 5 nD, down from over 200 nD when no corrections are made. Steady-state permeability measurements trend towards k1λ as confining stress is applied on plugs where microfractures appear to be minimal. Crushed-rock pressure-decay permeability, when corrected for flow-regime effects, offers the best measure of matrix permeability in shales.
Next to the Alaska Highway 97 north of Fort St. John in the thick forests of northern British Columbia natural gas is trucked out from the Highway Natural Gas Liquids Plant in the North Montney shale formation. Unconventional oil and gas have come to dominate the exploration and development scene in Western Canada since 2005, much as they have in the US. Both countries share essential elements needed to launch and sustain unconventionals: A long history of drilling, publicly available data, well-understood sedimentary basins, extensive infrastructure, a diverse corporate sector, and regulatory regimes supportive of innovative resource development. Following closely on developments in the US, the “tight gas” concept was a key component of the Canadian oil patch in the 1980s and 1990s. Horizontal drilling and hydraulic fracturing were employed in ever-tighter reservoirs, and in the early 2000s, Canadian operators began to appreciate the true potential of oil and gas from shales, tight reservoirs, and coal seams.
Todea, Felix (Shell Canada Ltd.) | Stephenson, Ben (Shell Canada Ltd.) | Tomlinson, Alexa (Shell Canada Ltd.) | Pratt, Heidi (Shell Canada Ltd.) | Williams, Will (Shell Canada Ltd.) | Acosta, Luis (Shell Canada Ltd.) | Speidel, Brad (Shell Canada Ltd.)
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 application of chemostratigraphy to problems in modern and ancient environments has a long and successful history. In particular, the use of high-resolution X-ray fluorescence (XRF) spectrometry for studying the elemental content of core and rock at the sub-millimeter scale to understand provenance, grain size, paleoredox state, terrigenous influence, and other aspects of strata is well documented in paleoclimatology literature.
Berner, U. and E. Faber, 1988, Maturity related mixing model for methane, ethane and propane, based on carbon isotopes, Organic Geochemistry, vol.