Organizational project management (OPM) carries within several professional capabilities.
The novel Yin-Yang OPMC model is filled with different organizational project management capabilities, which are subjectively grouped into micro (an individual), macro (an institution) and shared perspectives. These OPM capabilities will be discussed, as well as the notion of balance and harmony in the model. The model will be questioned and validated using project management literature. It will also be supported with examples from within and outside the oil and gas industry used as lessons learned.
The Yin-Yang OPMC model presented in this paper, underlines the importance of being able to look from broad perspective of an organization (represented by governance, processes and systems), as well as from individual perspective/workforce (employees working for an institution, who directly translate the organizational strategy into results), in order for an organization to be sustainable and progressive.
The model consists of the following macro-scale concepts: strategic objectives, strong governance, flexibility with stable processes, incentives, leadership, inter-organizational collaboration, maturity, broad and focused perspective, consistency/integrity, scanning of environment (an organization and market). Shared competences by micro and macro scales are: fit, collaboration/partnership, sustainability, values, ethics, networks, opportunities, balance, compromise, change, adaptation, integration, interactions, and learning. Whereas, the micro scale capabilities are the following: sharing, influence, individual, development, empowerment, fulfillment, innovation, working culture, sociability, and trust. Several examples have been presented in order to illustrate the concepts.
All these capabilities require the skills of balance – just the right amount and the skill of harmony –acceptance within an individual and an organization without losing the competitive edge, in order to reach the win-win status. This is necessary for an organization to thrive in fast paced and uncertain market.
The novel Yin-Yang OPMC model was built for better understanding of micro (individual focused) and macro (organization focused) capabilities and interactions between them. The OPM capabilities are important for the oil and gas industry to reflect on, in order to thrive in constantly changing and uncertain market, gain maturity, progress and maximize on project investments. The strategic objective is to align all stakeholders to the organizational strategic vision, thereafter everybody looks in the same direction.
Rivero, Jose Torres (Energy & Environmental Research Center) | Jin, Lu (Energy & Environmental Research Center) | Bosshart, Nicholas (Energy & Environmental Research Center) | Pekot, Lawrence J. (Energy & Environmental Research Center) | Sorensen, James A. (Energy & Environmental Research Center) | Peterson, Kyle (Energy & Environmental Research Center) | Anderson, Parker (Energy & Environmental Research Center) | Hawthorne, Steven B. (Energy & Environmental Research Center)
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.
Hydraulic fracturing for shale gas production involves pumping large volumes of water; as a consequence of this, produced water management is an important topic to address in order to sustainably produce shale gas. It has been well documented that only approximately 10-40% of the pumped fluids will be produced back to the surface, and that there will be increased concentrations of various ions in the flowback water during this process. This flowback water, with high total dissolved solids and high concentrations of certain ions, presents a significant risk of mineral scaling (
In general, it can be very challenging to identify the
A further two-phase 3D flow model was developed to examine the scaling tendency due to the evolving produced brine composition over the lifetime of the well. It is based on the previously history matched model and includes the fracture fluid and formation water compositions to predict precipitation of minerals. Finally, scale inhibitor injection was simulated to examine the impact of inhibitor retention on well protection.
Produced water chemical compositional data are collected from a carbonate reservoir which had been flooded by North Seawater for more than 20 years, so there is an opportunity to analyse the large amount of produced water data collected, understand the brine/brine and brine/rock interactions and explore the impact factors behind them. In some publications, core flood experimental tests were performed with chalk cores or carbonate columns in order to make an understanding of possible chemical reactions occurring triggered by injected water with different composition (Seawater, low salinity water or any other brine). However, most of the time the laboratory conditions where core flooding experiments are implemented cannot fully simulate the real reservoir conditions. Therefore, in this study, with the help of the valuable produced water dataset and some basic reservoir properties, a one-dimensional reactive transport model is developed to identify what in situ reactions were taking place in the carbonate reservoir triggered by seawater injection.
From the perspective of reservoir mineralogy, calcite, as the dominant mineral in the carbonate reservoir, is relatively more chemically reactive than quartz and feldspar which are usually found in sandstone. Whether calcite is initially and dominantly present in the carbonate reservoir rock is dissolved under seawater flooding or not is the first key issue we focused on. The effects of calcite dissolution on the sulphate scaling reactions due to incompatible brine mixing and the potential occurrence of carbonate mineral precipitation induced by calcite dissolution are investigated and discussed in detail. The comparison of simulation results from the isothermal model and the non-isothermal model show the important role of temperature during geochemical processes. The partitioning of CO2 from the hydrocarbon phase into injected brine was considered through calculation of the composition of reacted seawater equilibrated with the CO2 gas phase with fixed partial pressure (equivalent with CO2 content), then subsequently the impact of CO2 interactions on the calcite, dolomite and huntite mineral reactions are studied and explained. We also use calculation results from the model to match the observed field data to demonstrate the possibility of ion exchange occurring in the chalk reservoir.
The Piceance Basin is located in western Colorado and covers an area of about 7,100 square miles1. A spoon-shaped basin, sediments reach a maximum depth of about 20,000 feet near the central portion, and encompass rocks ranging in age from Tertiary to Precambian. The basin is bounded by outcrops on the east, west and south, and by uplifts that separate it on the north from the Sand Wash Basin and on the northwest from the Uinta Basin. There are massive tertiary intrusives – laccoliths and volcanics – on the southeastern portion of the basin that have elevated the heat flow there and a massive basaltic flow extended west across a portion of the central basin to form the caprock of the Grand Mesa area. Figure 1 is a geologic map of the Piceance Basin in western Colorado1.
Oil and gas exploration in the Piceance Basin dates to the early 1900’s, with the discovery of the Rangely field in the northwest portion of the basin. With the exception of Rangely and a few other small fields, the basin is dominated by wells that produce natural gas. Oil and gas production from the Piceance Basin Mancos was first established in the Rangely field area, as well2. To date, about 30,000 wells have been drilled and completed in the basin, and the vast majority of those that are active, about 15,000 wells3, are producing from the Upper Cretaceous Williams Fork formation sands of the Mesaverde Group, in the central portion of the basin
Mancos Exploration to Date
Gas production was established from the Mancos B sand along the western flank of the basin, an area known as the Douglas Creek Arch, that separates the Piceance and Uintah basins, near the Colorado-Utah state line. The Mancos B sand is a sandy interval in the upper portion of the massively thick Mancos Group shale. In May 2001, WPX Energy began gas production from the lower portion of the Mancos shale in the central portion of the basin, in its vertical Vassar Heath RMV 229-27 well, at Section 27-T6S-R94W, in the Rulison Field.
To date, about 120 Mancos shale oil and gas wells have been drilled, completed and placed into production, not including the aforementioned Mancos B sand wells located along the Douglas Creek Arch and the wells in the Rangely field area. About 56 of these wells are vertical completions, and about 64 are horizontal completions. Figure 2 shows the total production from these wells, along with the Nymex price of natural gas. Note that exploration for Mancos shale gas wells began around the time that Nymex natural gas prices began to decline, and that since gas prices reached a low in early 2016, Mancos development has been limited to a few wells per year.
Molecular diffusion plays an important role in shale oil recovery. CO2 huff-n-puff is a feasible way to recover shale oil in multistage fractured horizontal wells, and natural fracture is important during this process. In this work, the CMG-GEM model is built based on the Bakken formation geological settings and the Bakken live oil PVT data, in which natural fracture effective permeability is populated with a series of Dykstra-Parsons (DP) coefficients and spatial correlation lengths. DP coefficient varies from 0.396 to 0.867, and correlation length varies from 50 ft to 3,000 ft. CO2 huff-n-puff starts when primary recovery factor reaches 3%, in either single-cycle or multiple-cycle schemes: single-cycle is set with a fixed injected CO2 reservoir pore volume, and multiple-cycle is set with fixed huff/soak/puff days. Findings in this work highlight the complex molecular diffusion behavior in the comprehensive field-scale simulations. The findings imply the importance of accurate in-lab diffusion coefficient measurement between CO2 and light oil components. Besides, it is demonstrated that CO2 injectivity in shale reservoirs is a function of both natural fracture heterogeneity and distribution patterns.
The evidence from the produced-brine chemistry suggests that the Gyda field has experienced a variety of geochemical reactions caused by the high temperature and initial calcium (Ca) concentration, and so it is worth reviewing the produced-water data set and studying what in-situ geochemical reactions may be taking place.
Produced-brine-chemistry data from 16 wells in the Gyda field are plotted and analyzed in combination with general geological information and the reservoir description. A 1D reactive-transport model is developed to identify the possible geochemical reactions occurring within the reservoir triggered by seawater injection, and then extended with the inclusion of thermal modeling and also to be a 2D vertical-cross-section model.
Three possible classes of formation-water composition in different regions of the Gyda field have been identified by analysis of the produced-water data set. Anhydrite and barite precipitation are the two dominant mineral reactions taking place deep within the reservoir. Magnesium (Mg) stripping may be a result of multicomponent ion exchange (MIE), dolomite precipitation, or a combination of both. Reservoir temperature is lowered during coldwater injection. The solubility of anhydrite increases at lower temperature, and anhydrite will gradually dissolve in response to the movement of the temperature front, which is much slower than the formation/injection-water mixing front. The extent of mineral precipitation within the reservoir can be reduced by the heterogeneity; the modeling shows that the extent of ion stripping caused by mineral reactions in the reservoir is greatest when simulating a single uniform layer. Brine mixing and the occurrence of geochemical reactions caused by vertical mixing are not observable, even when assigning a high vertical permeability in a heterogeneous model.
Thermal modeling is included to evaluate the effect of nonisothermal processes and heat transport on the geochemical reactions, especially the anhydrite mineral reaction. We have investigated how the difference in horizontal permeability in the two layers affects brine mixing of formation and injection water and geochemical reactions.
The evidence from the produced brine chemistry suggests that the Gyda field has experienced a variety of geochemical reactions due to the high temperature and initial calcium concentration, and so it is worth reviewing the produced water dataset and studying what
Produced brine chemistry data from 16 wells in the Gyda field are plotted and analysed in combination with general geological information and the reservoir description. A one dimensional reactive transport model is developed to identify the possible geochemical reactions occurring within the reservoir triggered by seawater injection, then extended with the inclusion of thermal modelling and also to be a two dimensional vertical cross section model.
Three possible classes of formation water compositions in different regions of the Gyda field have been identified by analysis of the produced water dataset. Anhydrite and barite precipitation are the two dominant mineral reactions taking place deep within the reservoir. Magnesium stripping may be a result of multi-component ion exchange, dolomite precipitation or a combination of both. Reservoir temperature is lowered during cold water injection. The solubility of anhydrite increases at lower temperature, and anhydrite will gradually dissolve in response to the movement of the temperature front, which is much slower than the formation/injection water mixing front. The extent of mineral precipitation within the reservoir can be reduced by the heterogeneity; the modelling shows that the extent of ion stripping caused by mineral reactions in the reservoir is greatest when simulating a single uniform layer. Brine mixing and the occurrence of geochemical reactions due to vertical mixing are not observable, even when assigning a high vertical permeability in a heterogeneous model.
Thermal modelling is included to evaluate the effect of non-isothermal processes and heat transport on the geochemical reactions, especially the anhydrite mineral reaction. We have investigated how the difference in horizontal permeability in the two layers affects brine mixing of formation and injection water and geochemical reactions.
While there has been a steady increase in production from shale plays in recent years, recovery factors are still relatively low when compared to conventional formations. To improve on the existing technology and production from unconventional plays, a better understanding of reservoir fluid properties and phase behavior are vital. Understanding the dynamic behavior of reservoir fluids and the reliable prediction of reservoir performance in unconventional formations like shale are quite difficult. Reservoir simulation is an important tool that makes this easier and the type of reservoir simulation model used is a significant factor in this process.
This paper focuses on performance analyses of shale volatile oil reservoirs using black-oil and compositional simulation models. The performance analyses were done using single-phase (oil) and two-phase (oil and gas) black-oil simulations, as well as compositional simulations. The three approaches were compared in this paper. While black-oil simulations are easier, more accessible to the user and less time-consuming compared to compositional simulations, we assume that results are not as accurate as with compositional simulations. Nonetheless, how accurate are black-oil simulation results compared to compositional simulation results? Can the results be trusted to a reasonable extent? We have attempted to answer these questions and many others in this paper. The answers are vital because we cannot afford to use easier and less time-consuming methods at the expense of jeopardizing the accuracy of results of production forecasts.
Results show that the two-phase black-oil simulations are different and probably more accurate than single-phase black-oil simulations. As we have no field data to support our assumption for now, our opinion is based solely on the impact of the gas phase (for two-phase flow) on production performance. Also, the effects of fluid composition on cumulative oil production and oil rates were analyzed using compositional and two-phase black-oil simulations. Results from compositional simulations were different and presumably more accurate than two-phase black-oil simulations. This hypothesis is based on the fact that compositional simulation includes more of the physics that we assume are important in modeling reservoir fluids. Therefore, for thorough analysis of fluid composition effects and improved production forecasts (especially for reservoir fluids like volatile oils in shale formations), compositional simulations are necessary in most cases. We believe the compositional simulation will provide the most accurate forecasts, two-phase black-oil simulation will be the next most accurate, followed by single-phase black-oil simulation. However, this list is in inverse order of ease-of-use, so the simpler approaches are well worth considering to see whether they might be adequate. Finally, in this paper, the impacts of fluid sampling errors on cumulative oil production and oil rates were examined and found to have substantial effects on production forecasts.
Although the advantages of Low Salinity Waterflooding (LSW) have been widely reported, studies of LSW in the past two decades have mainly focused on the underlying mechanisms through core flooding experiments. For more successful and broader applications of LSW in the field scale, it is required to have a comprehensive understanding of the LSW performance with complex geological features on a large scale that has never been addressed in the past. This paper presents insights on field scale modeling and prediction of LSW to address the current challenges with: (1) an equation-of-state compositional simulator fully coupled to multiple ion exchanges, geochemical reactions, and wettability alteration; (2) incorporation of critical geological properties important in LSW; (3) effective closed-loop reservoir management for design and prediction of the LSW process; (4) LSW evaluation in a full field scale.
A mechanistic LSW model and a closed-loop modeling approach are introduced in this paper that can efficiently capture the critical effects of geology on the LSW process by integrating the use of geological software, a reservoir simulator and a robust optimizer. First, eighty geostatiscal realizations with different facies and lithology properties and distributions are generated to evaluate the effect of reservoir geology, in particular the critical effects of clay, on LSW. A wide range of recovery factors from 19% to 40% indicate that the effectiveness of LSW strongly depends on geological factors such as facies properties, clay distribution and clay proportion. In consistency with the laboratory and field-scale observations, wettability alteration has been identified as the dominant effect that contributes approximately 58% to 73% to the incremental oil recovery from these realizations. Detailed analyses of the key factors were addressed to allow the design of optimal injection strategies to maximize the oil recovery by LSW. LSW is then evaluated in a closed-loop reservoir management for a sandstone reservoir in both secondary and tertiary modes. It is found that secondary and tertiary LSW give about 6% and 4.1% incremental OOIP over high salinity waterflooding, respectively. The simulation results also indicate that the sooner the LSW process is started, the better the benefit is.