Hydrocarbons are trapped at great depths with pressure and temperature higher than surface conditions which would vary depending on reservoir properties. When the well is set on production, these hydrocarbons travel through the wellbore over reducing geothermal and formation pressure gradients. Hence, at shallower depths the temperature drops below the cloud point and sometimes, below pour point of crude thus creating an ambient temperature for the formation of wax and deposition of paraffin on the inner side of production tubing.
It has been observed that when hot fluid passes through a pipe which is covered by a continuously circulating hot water bath, the temperature difference of the fluid at surface outlet and sub-surface reservoir is reduced to a minimal value. This paper therefore proposes a practical application of such heat transfer within a wellbore for passively solving major industrial issues of paraffin depositions. The idea lies in minimizing the heat losses, which can be effectively done by insulating the inner side of the casing so that the annulus and fluid flowing within the tubing is isolated from exterior losses. According to the First law of Thermodynamics the fluid flowing within the tubing will experience reduction in thermal gradient. These loses can be compensated by injecting hotter brine through a pipe at the bottom of the annulus, which is isolated, using production packer. Further, circulating hot fluid in the annulus would result in isothermal heating of the fluid flowing through the tube which would minimize the heat loss across tubing, causing an increase in temperature of fluid at the surface above pour point. Several researchers have put forth heat transfer equations across the tubing's, annulus, insulator, casing, cement and the formation which can be used to calculate the overall heat transfer coefficient and thus, the amount of heat losses. Quartz sensors placed at the bottom of a wellbore would detect bottom borehole temperature based on which the injection temperature of fluid can be manipulated. The entire process can be automated by applying an artificial intelligent system which would monitor, control and respond. This method would increase the capex but would decrease the operating cost thus leading to an increase in the life of the well.
Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
Foaming in absorber column for sour gas treatment using amine is a common problem which adversely affects column performance leading to reduction in sales and fuel-gas production and solvent loss. Mostly antifoam injection has been a common method to counter the foaming, large dosage and frequent dosing of antifoam many a times aggravates the problem. This study details an alternative technique based on pressure pulse mechanism to control foaming in one of ONGC's gas sweetening plants.
One of ONGC's amine based sour gas sweetening plants faced severe foaming problem frequently. The feed rate is 200 kscm/hr and absorber column operating pressure is 51 kg/cm2. The experiment utilizes the property of surface tension which fluctuates with change in pressure of the system leading to foam collapse. The experimental procedure involved varying the sour gas feed rate, thereby creating pressure pulse inside the absorber column. Differential pressure across the column which is an indicator of foaming tendency is then monitored and controlled within 1.0 kg/cm2 and recorded for establishing effectiveness of the method.
It is observed that by providing a number of cycles of pressure pulse in the absorber, the differential pressure stabilizes gradually which indicates collapse of foam. It shows that whenever there is increase in feed, expansion of bubble takes place which provides high interfacial liquid-vapour contact. On the other hand whenever there is decrease in feed rate, compression of bubble takes place which provides low interfacial liquid-vapour contact. Surface layer surrounding the bubbles in a foam acts as a membrane or skin that can stretch or relax in response to change in pressure and gives a mechanical shock which breaks the bubble. The increase of size ultimately leads to instability and break-up of the upper surface and releases the liquid holdup. Hence by using feed rate spikes, the pressure of the bubble is pulsed to higher levels and returned to substantially the original level. This cycle continues for a selected number of times so that this pressure pulse travels through the liquid and bubbles and affects its surface tension. This results into a transition phase which in very high energy level breaks the bubble and releases the gas and decreases the liquid hold up and controls the foaming phenomenon.
This paper will gives an insight into a novel methodology of mitigating foaming problem in a sour gas treating absorber just by varying the feed rates in a controlled manner. This technique eliminates the need for injecting antifoam agents which in turn will reduce the operating expenditure of the plant. Adverse impact on environment due to excessive use of antifoam agent is also minimized.
In recent years, an industry-wide demand for increased drilling efficiency has led to the development of technologies and methods focused on multi-well pad development and the minimization of the transportation of drilling rigs between locations. Studies have indicated the potential for improving drilling cycle efficiency through improvements in rig design and procedural documentation but have given limited consideration to the unitization and mobilization practices surrounding ancillary components such as mud pumps, light plants, bulk fluid storage and other systems that comprise modern land rigs. This study examines current unitization practices, as well as offers alternative methods of integrating ancillary system components to improve current transport configurations. Specifically, ancillary systems whose transport dimensions and weight exceed the federal and state requirements for commercial vehicles operating within the National Highway Freight Network (NHFN).
In this study, the application of transport logistics software is used to demonstrate that there exists the potential for significant reduction in land rig mobilization costs through revised unitization of drilling rig ancillary systems. Permit data from proposed wells located in the Permian, Bakken, and Marcellus are utilized to develop transport scenarios whose focus is to quantify the impact of ancillary system unitization on the total fee structure associated with rig mobilization between geographical regions. Within each scenario, ancillary systems from currently active rigs are compiled and itemized according to their weight, transport dimensions, and degree of component unitization. The resulting schedule is then processed through transport logistics software to identify fee schedules associated with oversize permits, overweight permits, civilian and police escorts, driver rate/fuel costs, and associated service fees for the individual loads. Following the conclusions derived from the analysis of the existing rig systems, the series of transport scenarios are repeated using revised component configurations. The revised system employs a combination of divisible and non-divisible loads whose components are either integrated as part of dedicated transport trailers or located within ISO containers loaded onto commercially available transport trailers. The fee schedules from active rigs, as well as the results from the proposed unitization, are explored in detail to identify critical areas for improvement regarding unitization practices for active rigs and future builds.
Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids)
Equivalent circulation density (ECD) management is a key factor for the successfulness of the drilling operations, especially when dealing with narrow mud-weight windows. Poor management of ECD can result in unsafe and/or inefficient drilling as well as an increase in drilling cost due to associated nonproductive time (NPT). Different parameters can affect the ECD directly or indirectly including, but not limited to, wellbore geometry, cuttings, hole cleaning efficiency, flow rate, and rheological properties of the drilling fluid. However, the magnitude of the effect of each parameter is not well understood. In this paper, a comprehensive statistical analysis using the correlation coefficient was conducted using real field data to investigate the effect of three controllable factors - solid contents (SC), yield point (Yp), and plastic viscosity (PV) - on ECD.
The last several years has seen an increasing trend toward more depleted reservoirs and more challenging wells with tighter mudweight windows. Managed Pressure Drilling has been employed in these challenging well conditions, however industry take up has been slow for a number of reasons including technical, economic and deployment related. Those wells that have utilized Managed Pressure Drilling have tended to focus on the drilling related aspects of well construction. However, other areas of well construction such as casing and liner running and cementing and completion installation are equally and in some cases even more technically challenging. One area that has potentially hindered the uptake of Managed Pressure Drilling is that in general, and in particular in the well construction operations outside of on bottom drilling there has been no access to real-time downhole data. In particular this is related to real-time pressure data. Whilst cementing, displacing or completing then multiple fluid types and densities may be circulating both inside and outside the drillpipe, leading to significant challenges in simulations and models derived from surface data. To overcome this a new acoustic telemetry and measurement network is being deployed in depleted reservoir and managed pressure drilling operations to provide real-time downhole and along string measurements of pressures, temperatures and weights. Real-time data case histories will be shown from the Gulf of Mexico and the North Sea illustrating how this is being used to drive real-time decisions during drilling, cementing and completion installation operations in tight margin windows, depleted reservoir conditions and under managed pressure drilling operations.
The novel nanomaterial composition described in this paper has been designed to treat moderate to severe losses. The nanomaterial composition comprises an environmentally friendly nanoparticle based dispersion and a chemical activator. The design is based on a delayed activation chemistry to gel up a nanoparticle based dispersion.
Three different types of nanoparticles were used in the study to develop the novel loss circulation material. Two different types of negatively charged nanoparticle based dispersion and one positively charged nanoparticle based dispersion were used in the study. An inorganic activator has been used for the study. The effect of this inorganic activator on the gelation properties of the nanoparticle based dispersion was investigated. The gelling times were evaluated at different temperatures up to 300°F. The effect of activator concentration on the gelling time of the new composition has also been studied. The effectiveness of the newly developed composition as a loss circulation treatment was also evaluated by performing permeability plugging tests to test the plugging capacity of this novel system.
The novel nanomaterial composition is designed so as to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the treatment fluid inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system is designed so as to give a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures. This is an important advantage as it allows the loss circulation composition to remain pumpable for sufficient time for placement and develops the network structure that leads to gelation, over a predictable period of time. The set gel, which appears as a crystalline solid, could remain homogenous and stay in place thereby preventing loss circulation.
Commonly used fluid loss additives (FLAs) in today's invert emulsion drilling fluids include materials with various attributes. The unmet needs of existing materials may include: Environmental restrictions due to ecotoxicity or biodegradability concerns Performance issues at high temperatures Overdosing at high temperatures High costs Formation damage
Environmental restrictions due to ecotoxicity or biodegradability concerns
Performance issues at high temperatures
Overdosing at high temperatures
To address these challenges, a FLA was developed for invert emulsion drilling fluids that is made from a renewable raw material and performs at high temperature and high pressure. The renewable raw material used to make this novel FLA is a biopolymer byproduct of the paper pulping process, and was chemically modified under controlled conditions to create a high-performing FLA. Detailed testing was done to determine the additive's performance in different base oils (mineral and diesel), at various mud weights (12 to 16 ppg), at elevated temperatures and in different fluid systems characterized by rheology and high-pressure, high-temperature (HPHT) fluid loss. The novel FLA was compared to other commercially available FLAs for fluid loss performance.
The novel FLA outperformed or was on par with the industry available FLAs tested in this study. The novel FLA realized comparable fluid loss performance of less than 10 ml at 375 F at lower concentrations as compared to the industry FLAs. In some cases, the novel FLA performed at higher temperatures, whereas some of the industry available FLAs did not. The novel FLA also boosted the electrical stability (ES) of the emulsion in certain fluid systems. The novel FLA showed minimum change in the rheology of the oil-based fluids as compared to the industry available FLAs. The novel FLA demonstrated reasonable performance in different mud weights, base oils and fluid systems. Since this novel FLA is derived from a renewable raw material, it may have less of an environmental impact compared to other FLAs utilized today.
The novel FLA: Was developed from a renewable raw material for invert emulsion drilling fluids; Performed on par or outperformed industry available FLAs; and Boosted the ES of the emulsion for certain fluid systems.
Was developed from a renewable raw material for invert emulsion drilling fluids;
Performed on par or outperformed industry available FLAs; and
Boosted the ES of the emulsion for certain fluid systems.
An Under Balanced Drilling (UBD) pilot project in the Heera and Mumbai High fields of Western offshore India was recently completed successfully. The objective of the project was to establish whether the technology can improve productivity performance in the reservoir section, avoid reservoir damage and thereby enhance oil production from the wells. This paper incorporates the drilling experiences and challenges faced during execution of this pilot project, the well design considerations and methodology, evaluation of the drilling fluid systems and also describes the tangible benefits of using this technology in the drilling of these sections and wells. In terms of the productivity gains from drilling these wells using UBD technology, through the sub-hydrostatic formations offshore Mumbai, the results were very positive. With the success and encouraging results from the pilot project, more wells are now planned, including wells in the losses-prone and depleted Mumbai High and Neelam fields, to incorporate the experiences of the learning curve.
Drilling in high pressure high temperature (HPHT) deep gas reservoirs, with multiple shallow different pressure horizons, requires special techniques which include application of Managed Pressure Drilling (MPD), revising casing setting depths, improving casing strength, and refining mud design. This paper focuses on application of MPD in HPHT gas wells and also describes briefly other techniques which can improve drilling performance and reduce nonproductive time.