Mature field redevelopment involves the choice and implementation of different extraction techniques. This issue becomes more complex when the producing section is composed of isolated multilayer reservoirs with long and different production history which necessitates precise mangement of injection and production rates layer by layer and well by well. Geological discontinuities (Faults, pinch outs) also need to be taken into account when considering the injection of fluids in a multi-layered reservoir.
The present work, which involves a water flood, shows a method to define the contacted pore volume (CPV) evolution in time by dynamic simulation history matching, and thereby to determine the regions in each of the layers where changes in injection policy is justified. With the CPV defined at the end of the history match, the method allows an evaluation of the efficiency of the legacy secondary recovery scheme, and defines the corrective actions to improve it in each layer. This method is based on distribution of pore volume (PV) as function of water saturation i.e. PV(Sw) at each time before and after starting the injection in the reservoir. As a result, we can obtain the evolution of CPV since injection started, and then calculate the evolution of oil in place (OIP) in the CPV and compare this with total production of the layer considered, obtaining the efficiency of waterflooding layer by layer in different areas of the field. Extrapolating CPV(t) with the actual injection patterns allows an assement of CPV at the end of field concession, and gives us a base case forecast of future field behaviour.
As conclusions we observe that, this method is an easy and fast tool to determine the contacted pore volume evolution, and the efficiency of waterflooding. Further this method gives an estimation of Ultimate Contacted Pore Volume (UCPV) with the actual (or improved) injection configurations on a regional basis which allows further opportunity to be identified. The integration of this information with the actual field condition facilitates optimization of the water injection pattern and improves waterflooding productivity throughout the reservoir extension.
Petrocedeno block, located in the Junin Area of the Orinoco Heavy Oil Belt, is composed of the Main and South areas, and it has been drilled by more than 660 horizontal wells in a fluvial-deltaic environment using real time monitoring, and taking into account the response of gamma ray and resistivity logs and the structure of the seismic reflectors. The Main Area is about 324 Km2 and is covered by 3D seismic acquired in 1998 with a bin size of 15 m x 15 m, a nominal fold of 20 and a vertical resolution of 15 m.
Although the two drilling campaigns has been successful, every day the challenge to identify and to drill new targets is bigger, even with the incorporation of new technologies such as azimutal resistivity tools because the sand bodies are thinner, lateral facies variations are found more often and collision problems has increased. For those matters the improvement of the pre-existing seismic data with a reprocessing in the Main Area and the design of a new seismic in the South Area became a necessity. With the aim of drilling around 200 wells in the South Area, it was performed in 2011 the acquisition of a 3D3C seismic survey of 91 Km2, the first industrial 3D3C in the Orinoco Heavy Oil Belt, with the following characteristics: the use of DSUs, a record length of 8 seconds, a bin size of 10 m x 10 m and a nominal fold of 66. Parameters and characteristics were optimized from previous 3D3C pilots to improve the quality but also to perform elastic inversions from PP and PS seismic waves to better understand the subsurface and to get a reliable reservoir characterization.
A PP seismic Fast Track has been produced and has been used to start the delineation (vertical and slanted stratigraphic wells) and the development programs of the South Area, thus proving immediately its added value for Petrocedeno.
The lessons learned during the seismic design and acquisition will be useful to the future acquisitions in the Orinoco Heavy Oil Belt.
With increasing energy demand, the oil and gas industry requires new technological developments in the field of unconventional resources along with sustainable development. In this paper we put forward the concept of Bacterial Mat for optimised recovery from marine gas hydrates. Along the India's 7,500 km of coast line we have vast reserves of gas hydrates which can meet our needs for several centuries. Gas hydrate is a solid compound in which methane is trapped within a crystal lattice of water under high pressure and low temperature condition. The carbon content present in the form of gas hydrates is twice the carbon present in all known fossil fuels of the earth. One litre of gas hydrate contains on an average 168 litres of methane gas at STP.
The primary condition for the stability of gas hydrate is high pressure and low temperature i.e. a minimum depth of 300m and a temperature lesser than 2°C. Several technologies have been experimented for the extraction but the main problem faced was uncontrolled liberation of methane which is a powerful green house gas.
Our suggestion is to use Bacterial Mat for the optimised recovery of gas hydrates. This bacterial mat contains Archae bacteria. These bacteria can survive in extreme environment and can produce methane from CO2 & H2O. This process is exothermic and can raise the temperature to 140°C leading to escape of methane from gas hydrates. These bacteria will breed on an artificial animal intestine mat from which they will get nutrients for growth. The bacterial mat will be sent to the seabed and fixed to the bed with its arms on the edges where gas hydrates are deposited. After achieving the desired saturation of gas, it is produced from the sea surface installation.
The above suggested methodology is an optimised and economical way to recover gas hydrates. Firstly it will help to change the focus of extracting resources from conventional to unconventional resources. Secondly, it will lead to sustainable development and reduce the hazard of global warming to a large extent. Thirdly, this technology has huge potential in the petroleum industry.
The chemical treatment using surfactants/solvents can mitigate the liquid block by wettibility alteration in gas/condensate wells. Recently, its application has been extended from wettibility change in matrix to wettibility alteration in propant in hydraulic fractures and tested in field trials. The leak-off of working fluids into matrix may mitigate the liquid block in the matrix adjacent fracture walls unintentionally. However, it is not clear yet whether the mitigation in matrix from leak-off is significant, compared with the mitigation in the fracture propant, and how this may affect the job design. The experimental setup and associated results was for assessment of the treatment in fracture propant only. In the lab, the leak-off will not affect the flow in fracture since hydrocarbon is injected along the fracture to simulate the production. In reality, the hydrocarbon produce passing through the matrix blocks along fracture. And all previous modeling study and job design has ignored the leak-off. This work shows by simulation of a generic case how the leak-off may affect the design and outcome of the treatment.
This work clarifies several important design concerns for the chemical treatment in hydraulic fractured reservoir, which may be extended to natural fractured reservoir as well. This will affect the optimal treatment volume, prediction of outcome and economic evaluation. The leak off may bring little extra benefit from the removal of the block in matrix along fracture walls. But such extra benefit is not significant compared with that in the fracture propant. Due to leak-off, the treatment volume based on fracture volume is not adequate and the associated outcome prediction is optimistic. There is an optimal treatment distance along with fracture that had not been identified in previous study. There is not need to treat the fracture at its full length. Just the opposite, with leak off accounted for the attempt to treat the whole fracture will cost huge volume of working fluid and lead to extra liquid damage. The unintentional matrix treatment due to leak off will cost much more working fluid than the fracture treatment. Therefore, it is necessary to optimize the treatment volume during the job design.
Chemical treatment to remove liquid block in matrix and in hydraulic fracture
Li and Firoozabadi (2000) proposed an approach for stimulating gas condensate wells by changing the rock wettability towards non-liquid wetting in the near well-bore region. Kumar et al. (2006) reported improvement in gas and condensate relative permeability when Berea and reservoir sand stone cores were treated using a non-ionic surfactant. Bang et al. (2007) did extensive experiments for sandstone with a variety of new solvents containing a fluorocarbon polymeric surfactant. Ahmadi et al. (2010) reported successful wettability alteration in Texas Cream limestone and Silurian Dolomite cores. Effective solvent mixture was developed for delivering fluorinated chemical to the rock surface.
Drilling engineers frequently make expensive misjudgment due to improper prediction and control of pressure along the wellbore. The flow of fluid in the wellbore is complicated not only by contraction and expansion through tool joints, but also by the effect of pipe rotation.
Field data has proved the excessive pressure drop through tool joint. Extensive experimental and theoretical studies have been conducted to study the effects of tool joint and pipe rotation on pressure loss along the drillstring. However, there is a discrepancy between published studies about the effect of pipe rotation on pressure drop in pipe and annular flow. For Newtonian fluids, it is well known that pipe rotation does not affect the pressure drop. Nevertheless, for non-Newtonian drilling fluids, several experimental works reported the reduction of pressure loss; while other works reported the increase in pressure loss.
In this study, the flow of drilling fluid through contraction and divergence across the tool joint is investigated using Computational Fluid Dynamics (CFD) software package. Different pipe rotation speeds are used to simulate the flow of an incompressible Yield Power Law fluid in both pipe and concentric and eccentric annuli. The velocity and pressure profiles are analyzed and compared to emphasize the effect of tool joint and pipe rotation on pressure loss. The results show that pressure drop through tool joints is significant. Pipe rotation has small effect on pressure drop at low velocity, and different effects on pressure drop at higher velocity. Positive and negative effects depend strongly on flow geometry and flow velocity.
The results of this study provide valuable information about the flow of drilling fluids through tool joints and along the wellbore. These give useful insight into the effect of pipe rotation and tool joint on pressure drop. Accurate calculation of pressure drop along the wellbore with pipe rotation is highly important in hydraulic program, optimization and well control, especially for deepwater wells.
Fluid systems used for servicing wellbores are usually a combination of particulate materials of varying specific gravity, particle size, aspect ratio, and reactivity, such as lightweight materials/weighting agents, clays, fibers, elastomers, polymers, resins, salts, and cementitious materials in water or oil media. These fluids are more commonly referred to as ?complex fluids? and often exhibit a high degree of non-Newtonian and time-dependent behavior. To more efficiently and expeditiously perform well operations, it is beneficial to accurately probe the rheology of fluids (and their admixtures) under downhole conditions.
A novel, helical-shaped stator-rotor assembly was designed and developed to work around measurement errors arising from sample inhomogeneity, particle separation, wall slip, and coring-related issues with commonly used geometries, such as those of a bob/sleeve and vane. The rotor blade arrangement is a double helix with cut flights, whereas the stator unit has blades that are manufactured by parting a coaxial double helix offset to the envelope of the rotor. Constant relative separation between the stator blades and rotor vanes is maintained in all planes to create shear geometries that enhance in-situ mixing. This was leveraged to conducting compatibility testing.
Torque and rev/min data was collected for eight different Newtonian fluids with viscosities ranging from 10 to 1000 cp. The power number and impeller Reynolds number were plotted to derive functional relationships between these quantities in the laminar and turbulent regimes. Various complex fluids, including fracturing gels, viscoelastic fluids, oil, water-based muds, spacers, and cement slurries were tested on the helical mixer, a triangular impeller, and Couette geometries for comparative mathematical modeling.
A unified algorithm and data analysis protocol featuring the four-parameter generalized Herschel Bulkley model is presented to derive rheograms and yield stress. A comparison of experimental results with computational fluid dynamics (CFD) simulations is also presented.
Nonaqueous cement slurries have been used for many years to prevent unwanted water or gas production and to repair holes/cracks or other pathways that could have formed in the casing, cement column, or at the interface. Such slurries were forced or squeezed into flow channels and allowed to contact water being produced or otherwise inherently present. Exposure of cement to water presumably allows for setting of cement, thereby plugging the flow pathway. These nonaqueous cement slurries primarily contained cement, a nonaqueous fluid, and an oil-wetting surfactant. It was generally assumed that contact between cement and water allowed setting of the entire cement mass with ensuing good strength development, even though an efficient dynamic mixing of cement and water under downhole conditions is unlikely. In the laboratory, this is typically demonstrated by mixing (by means of agitation) the slurry and the required amount of water, allowing it to set at well temperatures and measuring strengths.
Laboratory mixing under quiescent conditions by addition of water to the top of nonaqueous cement slurry with no agitation, and allowing it to cure for many days, demonstrated setting of cement only at the interface as a thin solid film, while the remaining slurry was unset. It was not obvious whether the presence of set cement at the fluid interface prevented further ingress of water into the cement slurry, or if the cement particles in the bulk slurry remained too oil wet to allow hydration reactions. It was also not obvious whether a totally quiescent, totally dynamic, or an intermediate level contact between water and cement slurry truly simulated the downhole situation, accounting for the success of the technology. A surfactant combination was designed to allow deeper penetration of water into cement slurry under quiescent conditions. Details are presented.
Throughout the decades to come world's population is expected to rise as well as the energetic, food and water demand. All that, together with the everyday more rigid international environmental regulations alongside with the ongoing vertiginous technological advancement, will induce to a restructuration of global economy on the inter-governmental and institutional level in order to reinforce the fundamental pillars of sustainability: the environmental, social and economical. New energy systems will be implemented and scarcity of resources will be more severe, leading the economy not only to shift but to adapt to unconventional energy carriers and commodities. This combined with the targeted impact of these policies, concerning living standard improvements, social inclusion and carbon mitigation among others, will raise new and demanding challenges to face. This paper intends to present an overview of the energetic playing field throughout the transition towards a more sustainable world and the role of the Oil & Gas industry within this period. This article will identify and explain the challenges and constraints to be faced as well as the opportunities of undertaking ventures in this shifting environment. Also, the paper will broaden the concept of Green Economy, main theme of the 2012 UN's Conference on Sustainable Development, and present strategies to develop an energy system to function and sustainably endure in time within the mentioned framework and ex-plain why the O&G industry is a fundamental participant and a major "game changer" in this process. Petroleum holds a key role in this transition as being the most widespread energy carrier and the most competitive element of the current energy system. Therefore, the O&G industry has the opportunity to become the main "driver of change" and to impulse a more prosper and sustainable energy network for the world. It's imperative that the O&G sector keeps a long-term perspective in order to remain in force and profitable. This paper pro-poses some guidelines to do so and intends to raise awareness on the fact that sustainability is not only changing the way we analyze a project but moreover the way we do business in the O&G industry.
Einar Steensnaes, Minister for Petroleum and Energy of Norway, said during a speech given at the 2002 World Summit on Sustainable Development and speaking about the Petroleum Industry's perspectives for the future that "Increasingly, good ethics is good business". This simple and brief statement might be one of the clearest and most accurate ways of perceiving where the Energy Industry stands today and how it is preparing to face the challenges that the decades to come will bring. Today, the energy playing field is changing. Technology is advancing at the most vertiginous rate in history and it is only likely to accelerate. Energy has become an integral and fundamental part of human modern society and, most probably, man-kind's dependence and demand of energy will dramatically increase throughout this century. So, how will the Energy Indus-try overcome the complex challenges that ensuring energy security for such a fast moving world mean? The answer is right there: with good ethics.
Improved oil recovery (IOR) has been attracting renewed interest amongst many operators in Trinidad in recent times. High oil prices and government incentives have increased number of studies and pilot projects in secondary and tertiary recovery processes. Whilst IOR selection is driven by rock and fluid conditions, historically most operators still gave preference to infill and outstep drilling campaigns for that last hope of primary oil. Reviews conducted on Trinidad's past projects indicated mixed economic success of IOR projects with thermal flood projects being most successful.
Nitrogen injection has never been extensively analyzed or implemented in Trinidad and now more than before is the most opportune period to establish its place amongst the other injection mediums. This paper reviews the history and use of nitrogen injection around the globe, focuses on application to Trinidad's fields and analyses the reservoir/geologic parameter impact on recovery through reservoir simulation. Numerical simulation was performed on blocks within an onshore mature field and recovery results showed promising project potential. Simulation was also carried out on synthetic models which mimicked the various structural dips and porosity-permeability relationships that Trinidad's southern onshore acreage posses.
The findings herein, based on immiscible injection dynamics, explains the mechanism of nitrogen injection for Trinidad's shallow onshore reservoirs.
The overall results suggest that nitrogen injection is a real alternative and much more practical and economic than previously envisioned by investors. The technology of modern day reservoir simulation has made analysis fast and efficient using structural, stratigraphic and reservoir properties that reflects the subsurface in Trinidad. The encouraging results of this study means nitrogen injection for enhancing oil recovery can now be seriously considered by mature acreage operators who wish to lengthen the economic life span of their fields.
Hydrocarbon reservoir management of a mature reservoir is a complex process of deciphering the reservoir character, through dynamic static data integration, to produce an ideal depletion strategy for the field. A great result is normally a winning opportunity set or strategy defined by a marriage of maximum hydrocarbon recovery with fantastic economic indicators. Is it any wonder we invest heavily into tools and processes to achieve just this!
This paper will explore the use of structural and reservoir modeling tools and techniques to re-design an optimal depletion strategy for an oil and gas reservoir, in a predominantly gas field, in the Columbus basin off the East coast of Trinidad. This reservoir is a massive ~700 ft sand incorporating a 30~40ft thin oil rim with an underlying aquifer and overlain by a huge gas cap. Both oil and gas has been produced from this reservoir since 1998 by 8 oil wells and 4 gas wells spread across two fields.
Should the future of this reservoir first rely on targeting remaining oil or do we shift into high gas acceleration gear? To solve this conundrum all subsurface hands were brought on deck. The formulation of an appropriate depletion plan requires a multi pronged approach, as a clear alliance must be made between business objectives, reducing risk and good reservoir management practice.
A VIP/Nexus reservoir simulation model was the 'tool of choice' to investigate which depletion direction to forge ahead with. The first stage of this reservoir management investigation was the creation of a reliable structural model which then acted as the foundation for the build of a representative reservoir model. As part of this paper's journey, we delve into the process flow used to mimic this magnificent reservoir. We endeavor to deepen your understanding of, the application of crucial petrophysical modeling in the reservoir characterization procedure and the unmistakable impact of history matching over 12 years of production and pressure data. The result of this work was a fit for purpose reservoir model enabling the operator to make the right decisions for future development of this reservoir.