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Scale control and inhibition is very important for maintaining flow assurance of oil production. Several specialty chemicals are used to delay, reduce or prevent scale deposition and, in particular, polymers and phosphonate-based chemicals have been used extensively. The accurate and precise topside measurement of scale inhibitors plays an important role in assessing the efficiency of scale squeeze and continuous-chemical injection treatments. At present, numerous techniques exist for scale inhibitor (SI) analysis but each method has its own limitation and often these methods give results of either total chemical content or elemental analysis without details of chemical speciation. Furthermore, most techniques often lack the ability for on-site analysis on fresh produced water samples, which yields the potential for quick and more accurate and precise information due to minimal sample degradation.Nanotechnology-based Surface Enhanced Raman Spectroscopy (SERS) developed as the next-generation method to fill the gap in speciation of phosphonates and to determine low concentrations of different scale inhibitor chemicals in produced brines in a timely and cost-effective manner.Particular focus is placed upon the individual and mixed analysis of a novel phosphonate and Deta Phosphonate (DETPMP) respectively. Development of this method with handheld instrumentation provides better detection and quantification of scale inhibitors in the field and reduces time and cost compared to sending samples to off-site laboratories for data collection.
Scale inhibitor (SI) analysis is an extremely important part of scale management and it is essential to have reliable methods for the accurate and precise measurement of scale inhibitor residuals in produced fluids in order to prevent wells from scaling. This information enables key decisions on the efficiency of scale squeeze and continuous chemical injection treatments especially in remote environments. In remote fields, such as in desert and extreme winter environments, the ability to be able to monitor scale squeeze residuals on-site would offer significant potential to improve scale management capability through provision of rapid data which otherwise might not be available for several weeks due to long sample transport times to the laboratory. Since conventional scale inhibitor analysis methods are not suited for on-site analysis this has led to the development of a toolbox of technology options including suitable scale inhibitor squeeze chemistry coupled with advanced, on-site, "near online" scale inhibitor detection procedures including Fluorescence (F) and Time Resolved Fluorescence (TRF). In this paper, two field examples for on-site TRF analysis of polymeric scale squeeze inhibitors from remote wells in harsh environments will highlight the benefits of quick and timely scale inhibitor residual information. In the example from remote desert wells, a comparison of TRF and High Performance Liquid Chromatography (HPLC) analysis of the polymer residuals will show the accuracy and precision of the TRF method at low SI levels. In addition, an example for the proof of concept of detection of three different F Tagged sulphonated polymers in the presence of a phosphonate squeeze inhibitor and continuously injected untagged polymer will demonstrate the ability of "near on line" fluorescence techniques to improve scale management where four subsea wells are co-mingled in the same flow line. This paper concludes that fluorescence techniques are particularly suited to tagged polymers and naturally fluorescent molecules whereas Time Resolved Fluorescence provides the ability to detect untagged scale inhibitors like sulphonated copolymers, phosphonates and phosphate esters.
Scale deposition is one of the most common challenges encountered in oil and gas wells. Mature fields tend to have these issues, but tackling scale removal requires tedious diagnostic and intervention work due to uncertainty in determining the exact location and source of scale.
Production decline was observed in a High-Pressure High Temperature (HPHT) gas producer. Well testing was performed to assess and diagnose the production impairment. The preliminary well test data interpretation highlighted positive skin which needed to be characterized. Scale and even sand were considered as a possible cause of production impairment due to the nature of production chemistry and reservoir type, but the hypothesis lacked physical evidence in the wellbore.
A structured approach was adopted to identify, qualify and rectify the situation. High Pressure Coiled Tubing (HPCT) technology capable of providing real time down hole communication was utilized along with coiled tubing mounted downhole camera (DHC) to determine if the wellbore conditions were contributing towards the production decline resulting in a positive skin. The real time images acquired during the downhole camera run revealed astonishing details of the scale that was causing an impact in the production and the flowing wellhead pressure. The high-resolution images obtained during the well intervention clearly pin-pointed at the root cause of production loss and aided in designing a focused treatment for the challenge at hand. Given the sensitive nature of reservoir and possible interaction between the scale dissolving chemicals and reservoir, a customized treatment was formulated. The treatment design exploited the benefits of scale dissolution while preventing reservoir damage. The treatment was pumped using coiled tubing with a high-pressure jetting and rotating nozzle to ensure 360 degree wellbore coverage.
The well was opened to flow immediately after execution of the treatment. The post treatment flowback results indicated a resounding success with production almost quadrupling. A production log was subsequently performed to understand and gauge reservoir performance. The results of production logging further endorsed the fact that skin damage due to scale had been successfully removed and wellbore skin was reduced.
Scale inhibitor (SI) analysis is an extremely important part of scale management and it is essential to have reliable methods for the accurate and precise measurement of scale inhibitor residuals in produced fluids in order to prevent wells from scaling. This information enables key decisions on the efficiency of scale squeeze and continuous chemical injection treatments especially in remote environments.
In remote fields, such as in desert and extreme winter environments, the ability to be able to monitor scale squeeze residuals on-site would offer significant potential to improve scale management capability through provision of rapid data which otherwise might not be available for several weeks due to long sample transport times to the laboratory.
Since conventional scale inhibitor analysis methods are not suited for on-site analysis this has led to the development of a toolbox of technology options including suitable scale inhibitor squeeze chemistry coupled with advanced, on-site, "near on-line" scale inhibitor detection procedures including Fluorescence (F) and Time Resolved Fluorescence (TRF).
In this paper, two field examples for on-site TRF analysis of polymeric scale squeeze inhibitors from remote wells in harsh environments will highlight the benefits of quick and timely scale inhibitor residual information. In the example from remote desert wells, a comparison of TRF and High Performance Liquid Chromatography (HPLC) analysis of the polymer residuals will show the accuracy and precision of the TRF method at low SI levels.
In addition, an example for the proof of concept of detection of three different F Tagged sulphonated polymers in the presence of a phosphonate squeeze inhibitor and continuously injected untagged polymer will demonstrate the ability of "near on line" fluorescence techniques to improve scale management where four subsea wells are co-mingled in the same flow line.
This paper concludes that fluorescence techniques are particularly suited to tagged polymers and naturally fluorescent molecules whereas Time Resolved Fluorescence provides the ability to detect untagged scale inhibitors like sulphonated copolymers, phosphonates and phosphate esters. The two techniques can be used individually or in combination with each other and, in addition, offer the advantage of being able to detect polymeric and phosphonate scale inhibitors to minimum inhibitor concentration (MIC) of 1-2ppm and <1ppm respectively which offers potential to extend treatment lifetimes.
Wellbore instability has been experienced in areas of the Marcellus Shale and can become particularly troublesome in the superlaterals that are becoming more prevalent in that play. Often the instability while drilling these very long lateral wells is minimal; problems are more likely to occur while tripping out after reaching TD. The most common instability events when pulling out of the hole appear to be tight hole, pack-off and stuck pipe. These problems often worsen with time, indicating there is some time-dependence to the failure mechanism.
In order to develop effective mitigation strategies to combat the instability, it is imperative that the failure mechanism be correctly identified. Previous publications (Kowan and Ong, 2016; Addis et al. 2016; Riley et al. 2012) have suggested that bedding planes may play a role in some of the drilling problems experienced in the Marcellus Shale. In this paper, we will present a case study from the Marcellus that shows conclusive proof of weak bedding plane failure along a lateral well, where thousands of feet of anisotropic failure were captured with a LWD image log.
This image provided confirmation of the presence and failure of weak bedding planes in the Marcellus Shale. The image was also used to validate an existing geomechanical model for the area and gave the operator more confidence in the mitigation strategies developed from that geomechanical model, which had been based on the assumption that weak bedding was contributing to difficulty experienced on multiple lateral wells when tripping out of the hole.
This case study will begin with an overview of the geomechanical model, including the drilling history, stress/pore pressure model and rock properties. Next, some highlights from the image log, showing anisotropic bedding plane failure, will be featured as well as a comparison of the image to the geomechanical model. This case study will conclude with a review of proposed mitigation strategies that could be implemented by the operator to limit the risks posed by weak beds and minimize instability, when drilling laterals in this area, or similarly complex areas, of the Marcellus Shale.
Reservoir navigation, often referred to as geosteering, is commonly used to optimize the placement of highly deviated wells. This technology has contributed significantly to the prolongation and economic well-being of mature hydrocarbon provinces around the world and been a major enabler for the commercial success of unconventional reservoirs.
The reservoir information and analysis obtained during reservoir navigation is extensive and very valuable, yet is known to sometimes remain unused. Part of the reason is the complexity of reservoir navigation data and the limitations that many geosteering software applications cannot integrate the information provided from this data to update seismic-based 3D models.
This paper demonstrates a fast and effective method of utilizing spatial reservoir navigation information to improve the three-dimensional understanding of producing reservoirs. Reservoir navigation interpretations from one or more wells can be used as inputs. The results include updated structure maps, refined gross rock volume (eg shale volume in unconventional reservoirs), updated values for porosity and water saturation and ultimately a revised volumetrics calculation. The results can be compared with calculations from other methods such as material balance and decline curves. Analyzing conflicting field data and reconciling them creates opportunities for improved drilling opportunities and better reservoir development. Datasets used in the paper show some specific examples of how the 3D workflows lead to better field developments with enhanced drilling operations and improving recovery factors.
In the future, significant technical developments are expected in the type and complexity of reservoir navigation data originating from logging while drilling (LWD) tools. These data types will easily be included in the new 3D workflows without introducing undue complexity.
Integrating reservoir navigation interpretations into sub-surface 3D models can be of benefit for real time drilling operations and also for field studies. The method uses a 3D workflow that can be completed easily and is fast enough to update models in real time. It is therefore useful for the purposes of improving architectural and geomorphological understanding of an area larger in scale than just the immediate active well. This creates an information rich environment with insightful information during geosteering real time jobs for better decisions. Additionally, the analysis method can be performed as a field study. This more comprehensive approach allows integration with other information after drilling operations have ceased to improve resource recovery and pick better future drilling targets.
Acid tunneling is an acid-jetting method for stimulating carbonate reservoirs. Several case histories from around the world were presented in the past showing optimistic post-stimulation production increases in openhole wells compared with conventional coiled-tubing (CT) acid jetting, matrix acidizing, and acid fracturing. However, many questions about the actual tunnel creation and tunneling efficiency are still not answered. In this paper, the results of an innovative full-scale research program involving water and acid jetting are reported for the first time.
The tunnels are constructed through chemical reaction and mechanical erosion by pumping hydrochloric acid (HCl) through conventional CT and a bottomhole assembly (BHA) with jetting nozzles and two pressure-activated bending joints that control the tunnel-initiation directions. If the jetting speed is too high and the acid is not consumed in front of the BHA during the main tunneling process, then unspent acid flows toward the back of the BHA and creates main wellbore and tunnel enlargement with potential wormholes as fluid leaks off, lowering the tunneling-length efficiency.
Full-scale water- and acid-jetting tests were performed on Indiana limestone cores with 2- to 4-md permeability and 12 to 14% porosity, sourced from the same supplier. Many field-realistic combinations of nozzle sizes, jetting speeds, and casing pressures were included in the testing program. The cores were 3.75 in. in diameter × 6 in. in length for the water tests and 12 in. in diameter × 18 in. in length for the tests with 15-wt% HCl acid. The jetting BHA was moved as the tunnels were constructed, at constant force on the nozzle mole, to minimize the nozzle standoff. Six acid tests were performed at the ambient temperature of 46°F and two at 97°F. The results from the acid tests show that the acid-tunneling efficiency, defined as the tunnel length divided by the acid volume, can be optimized by reducing the nozzle size and pump rate. The results from the water and acid tests with exactly the same parameters to match the actual CT operations in the field show that the tunnels are constructed mostly by chemical reaction and not by mechanical erosion. The acid-tunneling efficiencies obtained from the full-scale acid tests are superior to the average tunneling efficiency of more than 500 actual tunnels constructed during more than 100 acid-tunneling operations performed to date worldwide. Although the tunnel lengths and acid volumes for the actual tunnels constructed during the previous acid-tunneling operations were recorded by the service company performing those operations, little downhole temperature and formation characterization data were provided by the operators to the service company. Thus, the downhole-temperature and formation-characterization effects on the acid-tunneling efficiency for the previous field operations are unknown.
In this paper, we describe the full-scale water- and acid-jetting tests on Indiana limestone cores. The major novelty of this test program consists of performing all measurements with casing pressure, unlike all previous water- and acid-jetting studies performed at atmospheric conditions and reported in the literature, which is closer to the field conditions during CT operations. The novel understanding of the combined effect of the nozzle size, pump rate, and casing pressure significantly improves the actual acid-tunneling efficiency.
Multiple industries are operating with the installed base of products, such as Valves for pipeline or fluid flow applications, Turbomachinery Equipment for power generating Plants, or Pumps for Oil & Gas Artificial Lift Services. This installed base of assets requires monitoring, predictive and preventative maintenance, as well as part or asset replacement when it is not performing to specifications. These additional performance requirements drive the Aftermarket business to maintain and repair these installed assets. One of the challenges is that many of the failure mechanisms resulting in part replacements or repair are unpredictable and require an immediate response to minimize operational downtime. Moreover, some assets are expected to last for decades, and in many cases, the original manufacturer is no longer in the business by the time the asset needs to be repaired or replaced. Often, the risk of part shortages is met by building and maintaining inventories, tying up cash in items that might never be used. Therefore, the nature of Aftermarket business places premium on quick response in spare part delivery and asset repair. This paper outlines how the relative simplicity and speed of Additive Manufacturing process can address this need and meet the associated demand with minimal inventory levels.
Additive Manufacturing (AM) is a novel manufacturing technology, growing rapidly and able to work with multiple materials, including many plastics, metal alloys, and ceramics. AM is characterized with relative simplicity and speed (less steps in Supply Chain process compared to conventional machining or casting), as well as ability to create very complex shapes for no additional cost and enabling favorable economic value for a product lot of one (thus solving mass customization challenge). These advantages make AM indispensable for the Aftermarket as it is uniquely positioned to meet quick response demands eliminating the need to hold inventories. Moreover, combining capabilities of AM with modern reverse engineering and modeling & simulation tools allows quick turnaround for parts that are no longer serviced by the original manufacturer.
We present several case studies on how AM is able to meet Aftermarket challenges in different businesses such as Valves and Turbomachinery Equipment, dramatically reducing lead time for spare parts and eliminating inventories. With rapidly growing footprint of AM, including new materials, larger and more versatile 3D printers, and scalable, economic processes, it is evident that the case for AM in Aftermarket business will only get stronger and we will see rapid proliferation of AM in many industries for years to come.
The application of AM processes to the Aftermarket business challenges results in a dramatic change of business models: no longer spare part shortage risks are addressed by building inventories; rather, speed of AM process allows meeting demand for part replacement and repair just in time, minimizing inventory levels and enabling economic Supply Chain solutions for a product lot of one.
Rotary steerable drilling systems are highly automated with inclination and azimuthal hold modes. These systems require only sparse communication downlinks to hold to a well plan or to compensate for geological "drift". Mud pulse transmission is one of the most complex communications technologies in any industry, yet measurement-while-drilling (MWD) companies have developed reliable bi-directional telemetry systems. The focus here has been on pulse generation and sophisticated decoding systems, able to detect signals, automatically, at a very low signal-to-noise ratio.
Combining downhole automation and automatic mud pulse decoding with remote operations technologies delivers the technical-basis for unmanned MWD and directional drilling (DD) services. The infrastructure for unmanned services is a reliable surface communications network that connects the rig site with the remote operations center, and the realization that unmanned operations needs a new organizational structure for subject matter experts (SME's), in this case the MWD and DD engineers.
This paper describes the now mature unmanned MWD and DD services (remote operations) in the US Land arena. These unconventional wells can reach in excess of a mile a day (so-called, MAD wells) with record footage in excess of 9,000 feet in a single 24-hour period. It will also describe the SME structure to deliver remote operations, and the key-role SMEs play in realizing unmanned operations. For example, moving directional drillers from the wellsite and into operator offices greatly improves decision-making.
The paper will also examine the role of automation and digital technologies within this construct, especially how they will allow the unmanned model to migrate towards complex wells. Automated trajectory drilling systems, in which the rotary steerables can automatically correct for geologic drift, is the next step in downhole automation, soon to be followed by automated geosteering. Unmanned remote operations have only been around for a couple of years, but already operators are realizing efficiency and performance as they take advantage of a real-time digital infrastructure.