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.
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.
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.
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.
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.
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.
Drozdov, Alexander Nikolaevich (Gubkin Russian State University of Oil & Gas) | Bulatov, Georgy (Gubkin Russian State University of Oil & Gas) | Lapouhov, Alexander Nikolaevich (Gubkin Russian State University of Oil & Gas) | Mamedov, Emil Adalatovich (Gubkin Russian State University of Oil & Gas) | Malyavko, Evgeny Alexandr (Gubkin Russian State U. of O&G) | Alekseev, Yaroslav L. (Gubkin Russian State U. of O&G)
One of the main reasons, leading to the production decline of gas and gas-condensate wells is the accumulation of liquid fluid on the bottom of the well and formation of liquid blockage. Under certain conditions, bottom hole pressure drops, flow rate
declines and gas velocity reduction becomes insufficient for the liquid lifting. Periodic gas purging of low-pressure wells practiced in Russia for water extraction, leads to the unproductive losses of hydrocarbons and forbids achieving stable operation. It leads to the retirement of wells out of the producing well stock, formation of dead zones with entrapped gas and, as the final result, to the waterflood hydrocarbon recovery drawdown. This problem can be solved by putting low-pressure flooded wells on pump, as international experience being indicative of its benefits.
Various engineering solutions based on the field tests of the techniques, mentioned above, were examined. The most suitable and viable technologies, for one of the Russian fields to be at the latest stage of reservoir development, were electric
submersible centrifugal pumps (ESP) and electric progressive cavity pumps (ESPCP): with the removing of water to the surface and the subsequent injection of water into injection wells, and also with the injection of water into the underlying aquifer in the existing producing well.
We developed a rational method of hydraulic calculation and selection ESP and ESPCP for different operating conditions. Preliminary bench experiments of ESP's, centrifugal gas separators and separator of mechanical impurities were carried out. The equipment has proven its efficiency.
The proposed solution will ensure the efficient functioning of the system of artificial-lift gas and gas-condensate well operation without using the unique expensive equipment. Also in a short period of time it could allow adapting the quantity produced submersible pumps for the conditions of gas industry.
The Dolphin Field is located in the East Coast Marine Area, approximately 60km off Trinidad. It comprises a 5,000 feet succession of stacked, unconsolidated, Pleistocene shoreface-deltaic sandstones and mudstones lying within a three-way dip, fault closure. The field is complicated by poor seismic data due to gas attenuation, fault shadow effects, large velocity variations and noise in the overburden. As a result the use of seismic amplitudes for fluid determination is unreliable and fault interpretation problematic.
Despite over 15 years of production, 5 exploration wells and 13 development wells there remains a high level of subsurface uncertainty. Specific areas of uncertainties include: zones of poor correlation as a result of large-scale sediment deformation; the configuration and sealing properties of both structural and syn-sedimentary faults; the effects of thin-bedded deposits (forming over 50% of the Dolphin reservoir intervals) on reservoir pay and connectivity; and the absence of all but one proven Gas Water Contact (GWC).
Defining the range of these uncertainties has a key impact on the range of GIIP outcomes, the resultant development plan and subsequent reservoir management. This paper will discuss the challenges and impact of these uncertainties on the Dolphin Field. The uncertainties identified on Dolphin form the basis for uncertainty planning in the development of subsequent analogous greenfields also within the Greater Dolphin Area.
As the industry continues to expand into ultradeepwater plays, an increasing number of tight tolerance wells warrant the use of an efficient system for determining early influxes or losses during drilling, tripping, and cementing operations. The narrow mud weight window for the majority of these wells requires an advanced solution in order to operate in all such conditions without compromising on safety. This paper describes a new early detection flow monitoring system and setup for floating rigs, and presents its application via a case study of a very high-profile ultra deepwater well.
Good well surveillance for floating rigs requires precise measurements combined with an efficient smart process adapted to deepwater conditions in order to raise a reliable alarm in any condition, while minimizing the risk of false alarms. Careful sensor selection and sizing, together with particular attention to installation is required in order to achieve this degree of accuracy for all the drilling phases. The solution described in this case study provides drilling surveillance for all hole sizes, with flow up to 2000 gpm for accurate and early detection, and significantly increased safety during drilling, tripping, and cementing operations.
This case study describes how kicks can be detected with a high degree of reliability much earlier than with the standard pit volume and flow paddle monitoring. In addition to this, it has shown its value by characterizing, in real time, the consequences following a packoff event and also by differentiating between a wash out and pump failure.
Crew confidence in this detection system rapidly led to modifications of the operational procedures. For instance, flow checks were previously done for every pipe connection, taking up expensive rig time. Due to results obtained in the previous hole sections, the drilling procedures were updated in order to significantly reduce time spent flow-checking, while still maintaining maximum safety during the operations.
Trigos, Erika Margarita (Universidad Industrial De Santander) | Rueda, Silvia Fernanda (Universidad Industrial de Santander) | Rodriguez, Edwin (Ecopetrol S.A.) | Espinosa Ortega, Jose Sebastian (Ecopetrol-ICP)
In Colombia, there are several heavy oil fields where cyclic steam stimulation have been successfully applied for over 25 years and although it is assumed that the reservoir temperature is high and the conditions are ideal for making the leap to
continuous steam injection, some studies apparently show that this technique is not feasible for the reservoir; in fact, between 1992 and 1994, the implementation of a pilot did not reach the expected results.
From this fact raises the question: What are the key factors that ensure the success of a continuous steam injection pilot? To solve this question, a numerical simulation and analytical model based study was performed, showing that the performance of the technique lies in minimizing the energy losses and supplying only the necessary heat according to each stage of the process, these practices are known as heat management.
It was found that critical aspects of heat management are: reducing well spacing, selection of open thickness to injection, perforated intervals, completion design, injector well distance from generator and injection surface line conditions, as well as
constant reservoir temperature monitoring, from which the energy requirements at each stage of the process is determined and avoid an excessive injection rate which goes against project economics.
For the field case it was found that: the well spacing should be reduced from 10 to 2.5 acres, the need of using selective sequential injection scheme (due the interbedded shale), the injection rate should be reduced to 46% a year after starting the
process and also change the type of insulation on the surface lines. In this paper, the methodology and tools used for factor evaluation and process optimization are presented.