Stimulation of Tight Formation in Kazakhstan by Chelate Based Treatment Fluids

Stimulation systems have improved over past decades, yet challenges prevail in corrosion, unwanted precipitation and handling hazardous chemicals. The role of chelating agents in coping with such concerns, is undeniably positive: their limited corrosivity, effective metal control and outstanding HSE profile, make them effective acidizing alternatives. Particularly when seeking delayed reaction at high temperature or removing insoluble material like Barite, chelating agents like GLDA and DTPA respectively have been reported effective both at laboratory and field scale. Formulations based on abovementioned chelating agents were evaluated experimentally to assess potential stimulation of Kazakhstan formations. Core-plug samples used in this evaluation are predominantly carbonate rock originating from different wells. The coreflooding experiments were performed at HPHT conditions to assess performance of treatment fluids to a) create new flow-channels (wormholes) thus improving rock permeability, and b) remove BaSO4-based solids suspected to be affecting productivity in the field. In this work, five reservoir core plugs were stimulated by GLDA based formulation to assess wormholing mechanism, while two core-plugs were treated by DTPA based fluid to study the impact of matrix cleaning. The matrix cleaning properties of DTPA based fluid were investigated on the damaged core plugs which were artificially damaged by in-situ precipitation of BaSO4 scale. The coreflood study included injection of the preflush, the treatment fluid and the post-flush system at reservoir temperature of 270 °F and low injection rates to accommodate the low permeability of the formation. It was shown that GLDA based fluid can effectively stimulate the reservoir core samples. The effective mechanism was observed to be wormholing thus increasing rock permeability by over a thousand times. No signs of face dissolution were observed despite slow injection rate at such high temperature; something that was not possible when a fast reacting acid (i.e. HCl) was used under the same conditions. In addition, it was shown that the DTPA based fluid can efficiently improve the rock permeability through matrix cleaning by both Barium and Calcium chelation. In the first treatment test by this fluid system, around 45% of the damaged permeability was recovered. While in the second test, not only BaSO4 scale was dissolved but also the CaCO3 minerals were partly dissolved and the core permeability was significantly increased (Kf/Ki >200). Experimental results bring promising prognosis for field implementation despite expected low injectivity at high downhole temperature. GLDA treatments avoid premature acid spending and face dissolution - common outcomes of HCl- which translate into deeper extent of stimulation. Additionally, in barite damaged wells, DTPA treatment represents an attractive solution for damage reduction and by-passing. Finally, intrinsic properties of chelating agents reduce asset integrity risks, improve operation HSE and simplify flow-back handling.

Designs for Reliability and Failure Mode Prevention of Electrical Feedthroughs in Integrated Downhole Logging Tools

To enable an electrical feedthrough integrated down-hole logging tool to maintain high reliability during its logging service in any hostile wellbores, it is critical to apply some guidelines for the electrical feedthrough designs. This paper introduces a safety factor-based design guideline to ensure an integrated electrical feedthrough has sufficient compression or thermomechanical stress amplitude in the stress well against potential logging failures. It is preferred to have a safety actor of 1.5–2.0 for an electrical feedthrough at lowest temperature, such as −60°C, and a safety actor of 2.5–5.0 at operating temperature range of 200–260°C. Moreover, the designed ambient pressure capability should be 1.5–2.0 times higher than the maximum downhole pressure, such as 25,000–30,000 PSI. To validate this thermomechanical stress model, several electrical feedthrough prototypes have been tested under simulated 200–260°C and 31,000–34,000 PSI downhole conditions. The observed testing data have demonstrated that there is a maximum allowable operating pressure for an electrical feedthrough operating at a specific downhole temperature. It is clearly demonstrated that an electrical feed-through may operate up to 60,000 PSI at ambient temperature in a real-life application, but it may actually operate up to 30,000–35,000 PSI at 200–260°C downhole temperatures.

Offshore Implementation of Temperature Microchip Under Critical Well Conditions

Drilling microchips are millimeter-size sensing devices, capable of measuring in-situ downhole temperature, and at the same time, withstanding harsh downhole conditions. In this work, 140 microchips were dropped from the drill pipe during the connections. The devices travel through the bottomhole assembly (BHA), drill bit, annulus, and eventually get recovered at the shale shaker. A total of 80 microchips were recovered at the shaker, which resulted in a physical recovery rate of 57%. The microchip recorded the dynamic temperature profile of the entire wellbore including a long openhole section only a few hours before the well turned into total loss. The data downloaded from the microchip shows an excellent consistency throughout the three tests. The measured dynamic bottomhole temperature provides a correction of 10 deg F to the best practice of the industry in terms of downhole thermal simulation, offering valuable measured input for the optimization of thermal activated LCMs or cementing job. To our best knowledge, it is the industry's first successful attempt in logging an openhole section in a highly loss zone. The microchip recorded the dynamic temperature profile of a long open hole only a few hours before the well turned into a total loss. Due to the lack of industrial solutions for downhole temperature measurement under such conditions, the microchip technology showed unique advantage for critical applications, especially in operations with highly valued assets.

Effect of Drilling Fluid Temperature on Formation Fracture Pressure Gradient

During drilling oil, gas, or geothermal wells, the temperature difference between the formation and the drilling fluid will cause a temperature change around the borehole, which will influence the wellbore stresses. This effect on the stresses tends to cause wellbore instability in high temperature formations, which may lead to some problems such as formation break down, loss of circulation, and untrue kick. In this research, a numerical model is presented to simulate downhole temperature changes during circulation then simulate its effect on fracture pressure gradient based on thermo-poro-elasticity theory. This paper also describes an incident occurred during drilling a well in Gulf of Suez and the observations made during this incident. It also gives an analysis of these observations which led to a reasonable explanation of the cause of this incident. This paper shows that the fracture pressure decreases as the temperature of wellbore decreases, and vice versa. The research results could help in determining the suitable drilling fluid density in high-temperature wells. It also could help in understanding loss and gain phenomena in HT wells which may happen due to thermal effect. The thermal effect should be taken into consideration while preparing wellbore stability studies and choosing mud weight of deep wells, HPHT wells, deep water wells, or wells with depleted zones at high depths because cooling effect reduces the wellbore stresses and effective FG. Understanding and controlling cooling effect could help in controlling the reduction in effective FG and so avoid lost circulation and additional unnecessary casing points.

Novel Solution For Curing Total Losses in Highly Fractured Reservoir Formation on a Major Oil Producing Field in the Middle East

The reservoir formation in a major oilfield in South of Iraq is highly fractured. The operator has set as requirement that any losses had to be cured before drilling ahead. Whenever losses are encountered, drilling is stopped to cure the losses, most of the times spotting at least four cement plugs before drilling ahead are required. The current process leaves the well in an underbalanced condition for a long time posing well control risk. It was necessary to come up with an optimized solution that reduces this exposure. Drilling the entire reservoir formation to expose all loss zones before spotting cement plugs to cure all the losses was the first step taken. Secondly, since encountering total losses across the reservoir formation was inevitable, redesigning the cement slurry formulation was an objective. Many alternative designs were proposed but were disqualified as some of the chemicals or fibers were not bio-degradable causing some damage to the reservoir. After a consensus between all parties, it was proposed to introduce temperature-degradable fibers into the cement slurry. Pilot tests were performed at maximum anticipated downhole temperature which proved successful. The analysis results from the lab were approved and one well was assigned for the field test of the proposed solution. The selected well was drilled to expose all the loss zones, losses were encountered as expected, cement slurry incorporated with temperature degradable fibers was spotted which resulted in all the losses getting cured at the first attempt. This solution was tested in all subsequent wells drilled on the field achieving the same successful result. This solution has since been adopted for curing total losses encountered across the reservoir formation in this field as it ensures that less time is spent on curing losses, less cement material is consumed and those wells are delivered quicker and at reduced cost. This solution has led to average savings of approximately 5 days per well drilled subsequently on this field. Previously it took an average of 166 hours to restore fluid well control barrier (see wells 1 and 2 in figure 2), these days in 52 hours fluid well control barrier is fully restored barrier (see wells 3 and 4 in the attached image). Well control risk is greatly reduced. This paper will show how minor changes to operational procedure and improvement to conventional solutions can greatly impact well control and the quick restoration of well barrier element when drilling across highly fractured reservoir formation. It will also discuss the comprehensive analysis of the loss zones, the cement laboratory analysis, the trial jobs, the measures that were put in place to reduce operational risks in order to ensure that the job was executed successfully.

Designs for reliability and failure mode prevention of electrical feedthroughs in integrated downhole logging tools

To enable an electrical feedthrough integrated downhole logging tool to maintain high reliability during its logging service in any hostile wellbores, it is critical to apply some guidelines for the electrical feedthrough designs. This paper introduces a safety factor based design guideline to ensure an integrated electrical feedthrough has sufficient compression or thermo-mechanical stress amplitude in the stress well against potential logging failures. It is preferred to have a safety actor of 1.5~2.0 for an electrical feedthrough at lowest temperature, such as −60°C, and a safety actor of 2.5~5.0 at operating temperature range of 200~260°C. Moreover, the designed ambient pressure capability should be 1.5~2.0 times higher than the maximum downhole pressure, such as 25,000~30,000PSI. To validate this thermo-mechanical stress model, several electrical feedthrough prototypes have been tested under simulated 200~260°C and 31,000~34,000PSI downhole conditions. The observed testing data have demonstrated that there is a maximum allowable operating pressure for an electrical feedthrough operating at a specific downhole temperature. It is clearly demonstrated that an electrical feedthrough may operate up to 60,000 PSI at ambient temperature in a real life application, but it may actually operate up to 30,000~35,000 PSI at 200~260°C downhole temperatures.

Field Application of Deep Learning for Flow Rate Prediction with Downhole Temperature and Pressure

Well real-time flow rate is one of the most important production parameters in oilfield and accurate flow rate information is crucial for production monitoring and optimization. With the wide application of permanent downhole gauge (PDG), the high-frequency and large volume of downhole temperature and pressure make applying of deep learning technique to predict flow rate possible. Flow rate of production well is predicted with long short-term memory (LSTM) network using downhole temperature and pressure production data. The specific parameters of LSTM neural network are given, as well as the methods of data preprocessing and neural network training. The developed model has been validated with two production wells in the Volve Oilfield, North Sea. The field application demonstrates that the deep learning is applicable for flow rate prediction in oilfields. LSTM has the better performance of flow rate prediction than other five machine learning methods, including support vector machine (SVM), linear regression, tree, and Gaussian process regression. The LSTM with a dropout layer has a better performance than a standard LSTM network. The optimal numbers of LSTM layers and hidden units can be adjusted to obtain the best prediction results, but more LSTM layers and hidden units lead to more time of training and prediction, and LSTM model might be unstable and cannot converge. Compared with only downhole pressure or temperature data used as input parameters, flow rate prediction with both of downhole pressure and temperature used as input parameters has the higher prediction accuracy.

Long-term recordings at the FSU Jena Geodynamic Observatory Moxa (Thuringia, central Germany)

<p>The remote location of the Geodynamic Observatory Moxa of Friedrich-Schiller University Jena, about 30 km south of Jena in the Thuringian slate mountains, results in very low ambient noise and thus very good conditions for long-term geophysical observations, which are further improved, as many sensors are installed in the subsurface in galleries or in boreholes.</p><p>So far, the focus of Moxa observatory has been on observing transients signals of deformation and fluid movements in the subsurface. This is accomplished by sensors like a superconducting gravimeter CD-034, three laser strain meters measuring nano-strain along three galleries in north-south, east-west and NW-SE directions, or borehole tiltmeters. Further, information on fluid flow is gained from downhole temperature measurements employing an optical fiber. These sensors are complemented by a climate station and two shallow drill-holes, one of which has been fully cored, which in addition to the temperature times series provide information on water level and rock physical properties. Near surface geophysical profiling using e.g. electrical resistivity tomography has led to a good knowledge of the structurally complex subsurface of the observatory.</p><p>Recently, a node for the Global Network of Optical Magnetometers for Exotic physics (GNOME) has been installed in the temperature-stabilized room at Moxa observatory close to the superconducting gravimeter. The GNOME is a world-spanning collaboration employing optically pumped magneto­meters (OPM) to search for space-time correlated transient signatures heralding exotic physics beyond the Standard Model. GNOME is sensitive to prominent classes of dark-matter scenarios, e.g., axion or axion-like particles forming macroscopic structures in the Universe. The installation in close vicinity to the superconducting gravimeter ensures well-controlled and -monitored ambient conditions such as temperature, air pressure and especially vibrations, allowing improved vetoing of false-positive detection events in the Moxa GNOME node.</p><p>Here, we focus on introducing Moxa Observatory’s sensor systems with an emphasis of actual sensor configurations and further on highlighting how various information on fluid flow coming from the specific sensors lead to an improved understanding of the direction and magnitude of subsurface fluid flow.</p>

Development of gasification agent injection tool for underground coal gasification

The underground coal gasification (UCG) technology is basically mature, but the influence of its own process and tools slows down its industrialization progress. This paper introduced the development and field test of two new UCG coiled-tubing gasification agent injection tools. The test results show that the two kinds of gasification agent injection tools ensure the injection point under control by conducting downhole temperature measurement and ground monitoring jointly. The problem that the tool is burnt by the backfire is solved by designing a backfire prevention device. To realize low pressure drop, the gasification agent flow channel inside the tool is designed optimally to keep the tool pressure drop not more than 0.5 MPa and the system pressure drop not more than 3 MPa. The tool overall has the characteristics of low pressure drop, high temperature resistance, backfire prevention and anti burning to satisfy the demand of the field test. This technology is a new achievement in the development of UCG technology and equipment in China. The research conclusions can provide technical reference for developing a new generation of UCG technology.