Heavy oil is defined as liquid petroleum of less than 20 API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12 API gravity and greater than 10,000 cp are sometimes used to define oil sands. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation.
A passive tracer that labels gas or water in a well-to-well tracer test must fulfill the following criteria. It must have a very low detection limit, must be stable under reservoir conditions, must follow the phase that is being tagged and have a minimal partitioning into other phases, must have no adsorption to rock material, and must have minimal environmental consequences. The tracers discussed in the following sections have properties that make them suitable for application in well-to-well test in which dilution volumes are large. For small fields in which the requirement with respect to dilution is less important, other tracers can be applied. Figure 1.1 – Production curve of S14CN compared with the production curve of HTO in a dynamic flooding laboratory test (carbonate rock) (after Bjørnstad and Maggio). There are no possibilities for thermal degradation, and it follows the water closely. The 36Cl- is a long-lived nuclide (3 105 years), and the detection method is atomic mass spectroscopy rather than radiation measurements. The disadvantage is that the analysis demands very sophisticated equipment and is relatively time consuming. For mono-valent anions, the retention factors (see Eq. 6.2) are in the range of 0 to -0.03, which means that such tracers pass faster through the reservoir rock than the water itself (represented by HTO). A compound such as 35SO42- may be applied in some very specific cases but should be avoided normally because of absorption. Some anionic tracers may show complex behavior. Radioactive iodine (125I- and 131I-) breaks through before water but has a substantially longer tail than HTO. Both a reversible sorption and ion exclusion seem to play a role here. Cationic tracers are, in general, not applicable; however, experiments have qualified 22Na as an applicable water tracer in highly saline (total dissolved solids concentration seawater salinity) waters. In such waters, the nonradioactive sodium will operate as a molecular carrier for the tracer molecule. Retention factor has been measured in the range of 0.07 (see Eq. 6.2) at reservoir conditions in carbonate rock (chalk). Wood reported the use of 134Cs, 137Cs, 57Co, and 60Co cations as tracers.
The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years). The first discoveries in the Canadian heavy-oil belt were made in the Lloydminster area in the late 1920s. Typically, 10- to 12-mm diameter perforations were used, and pump jacks were limited by slow rod-fall velocity in the viscous oil to a maximum of 8 to 10 m3/d of production, usually less. Operators had to cope with small amounts of sand, approximately 1% in more viscous oils. Small local operators learned empirically that wells that continued to produce sand tended to be better producers, and efforts to exclude sand with screens usually led to total loss of production. Operators spread the waste sand on local gravel roads and, in some areas, the roadbeds are now up to 1.5 m higher because of repeated sand spreading. The sharp oil price increases in the 1970s and 1980s led to great interest in heavy-oil-belt resources (approximately 10 109m3). Many international companies arrived and introduced the latest screen and gravel-pack technology but, in all cases, greatly impaired productivity or total failure to bring the well on production was the result. To this day, there are hundreds of inactive wells with expensive screens and gravel packs. The advent of progressing cavity (PC) pumps in the 1980s changed the nonthermal heavy-oil industry in Canada. The first PC pumps had low lifespans and were not particularly cost-effective, but better quality control and continued advances led to longer life and fewer problems. The rate limits of beam pumps were no longer a barrier and, between 1990 and 1995, operators changed their view of well management.
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
Rodriguez, Inti (Petrolera RN LTD.) | Hernandez, Edgar (Petrolera RN LTD.) | Velasquez, Richard (Petrolera RN LTD.) | Fernandez, Johanna (Petrolera RN LTD.) | Yegres, Frandith (Petromonagas) | Martínez, Rosana (Petromonagas) | Contreras, Ronald (Petrolera RN LTD.) | Korabelnikov, Alexander (Petrolera RN LTD.)
The Morichal reservoir at the Cerro Negro Extra Heavy Oil Field (Petromonagas JV) is starting its mature development phase after more than 18 years of production. In order to improve the current recovery factor which is around a value of 3%, maintain the production and reduce operational costs, two different strategies were defined: First, the use of the Jobo Member (overlaying sand deposits) to dispose the wastewater produced from the Morichal reservoir and second, the use of the shallow aquifer deposits of Las Piedras Formation as a water source for future massive implementation of EOR projects (Polymer and steam flooding), evaluating the potential origin of this water based on its physical and chemical properties. Both geological units are part of the drilled stratigraphic column of The Cerro Negro field, what brings technical and economical advantages such as high density of geological information available and the reuse of abandoned wells. This paper aims to describe the study case of the Cerro Negro Oil Field where on one hand, a static and dynamic characterization of Jobo Member was carried out in order to define the potential areas to be used as a wastewater disposal of the Morichal Member production. Based on the geological characterization, dynamic evaluation and surface facilities analysis, it was selected as the best area to dispose of more than 35,000 B/D of water derived from the production of 330 horizontal wells drilled; as well as, support the strategy of producing wells with high water cuts in zones of perched water and close to water contacts, where an important volume of oil is located which until now has been bypassed. On the other hand, the aquifer characterization of Las Piedras has allowed us to define the volume and composition of water available to use as a secure and probed water source during the EOR project implementation.
Hafez, Hafez (ADNOC) | Al Mansoori, Yousof (ADNOC) | Bahamaish, Jamal (ADNOC) | Saputelli, Luigi (Frontender) | Escorcia, Alvaro (Frontender) | Sousa, Sergio (Halliburton) | Rodriguez, Jose (Halliburton) | Mijares, Gerardo (Halliburton)
Identifying opportunities in the installed capacity and proactively mitigating the limiting factors are paramount objectives for pursuing profitable production assurance. Although integrated asset modeling has been the de facto technology for supporting production planning and optimization work processes, its application is not fully adopted as it presents challenges when attempted to be used in a large-scale of multiple oil and gas assets.
This paper describes ADNOC’s innovative approach to develop a large scale subsurface to surface integrated asset modeling (LSSSIAM) solution by focusing on the desired business outcome. The paper introduces a new concept of right complexity modeling (RCM) to drive the type and level of complexity of the model/simulation based on the desired business outcome and other factors that influence the quality of the decision-making process.
The methodology has been applied on a large-scale of multiple assets for effective production assurance that integrates the subsurface to the surface physical phenomena as required by the desired business outcome—the technical assurance of production plans within the context of a country. For the presented example, the proposed methodology resulted in the design of a solution where the subsurface phenomena are represented with a data-driven model to specifically address the requirements of the decision-making process which the solution supports.
This resulted in the development of a first-of-its-kind countrywide production model that rigorously considers the properties and physics from the wells to the point of supply while also considering the subsurface phenomena as related to the production potential of the reservoirs and wells.
The solution leverages the rigor of first-principle reservoir models to obtain a data-driven proxy model suitable for integration with a first-principle model covering more than 7,000 wells, multiple network and asset facilities, and a supply point transfer countrywide network. The solution can run in a matter of seconds, allowing for the optimization of a desired objective function or the effective analysis of operational scenarios, which can include short- and mid-term production assurance, opportunities identification to increase production to capture value opportunities from a country-wide production capacity context, and compensating for possible shortfalls resulting from unplanned operational disturbances in other assets.
Summary A workflow to generate seismic well ties in PS converted wave seismic sections using sonic logs was created by estimating Vp/Vs relationships and the time difference between the arrival time of the P-P and the PS waves to several key events. The results were PS converted wave synthetic seismograms tied to well-defined seismic reflectors at different depths. These positive results made possible the creation of a step by step workflow to tie wells to converted wave seismic and generate synthetic seismograms. Introduction The seismic method of reflection P-P wave has been the most important exploration method in the oil and gas industry. Nevertheless, this method does not clarify all the uncertainties that can be encountered during subsurface exploration and development.
This advanced course is intended for artificial lift and production professionals currently working with or managing ESPs. The teardown (or dismantle) of the ESP is the final phase of an ESP’s operation, but one that can give the most information on how the ESP performed during its life. Additionally, and maybe more importantly, the teardown and subsequent analysis can tell you why it failed. This key step is not simply taking each component apart, the ESP must be disassembled in a particular order, carefully inspecting for specific failure modes at each step, and, that order may vary with conditions and circumstances. Executive Plenary Session 1: Intelligent Lift 4.0 In the last two decades, the world has witnessed how efficient data flow among devices connected to the internet and machines has transformed and enhanced human lives and fundamentally altered every industry in what is known as the 4th Industrial Revolution.
Bao, Yu (Research Institute of Petroleum Exploration & Development, CNPC) | He, Liangchen (Liaohe Oilfield Company Ltd, Petrochina) | Lv, Xue (Sino-Pipeline International Company Ltd.) | Shen, Yang (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Xingmin (Research Institute of Petroleum Exploration & Development, CNPC) | Liu, Zhangcong (Research Institute of Petroleum Exploration & Development, CNPC) | Yang, Zhaopeng (Research Institute of Petroleum Exploration & Development, CNPC)
The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters.
The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.