Noble, L. (Schlumberger Oilfield Services) | Govil, A. (Schlumberger Oilfield Services) | McCann, C. (Schlumberger Saudi Arabia) | Obando Palacio, G. A. (Schlumberger Oilfield Services) | Knutsen, O. (ConocoPhillips Co) | Nesland, B. (ConocoPhillips) | Mueller, D. T. (ConocoPhillips)
As the fields in the North Sea mature, many of wells undergo permanent well abandonment or permanent abandonment of a section of the well for consequent well sidetracking. Compliant procedures for well abandonment as per Norwegian Continental Shelf regulatory requirements necessitates the presence of double barriers to isolate permeable formations/sources of inflow. To achieve a compliant plug-and-abandonment case in situations where casing cement is part of the primary or secondary well barrier (forming part of an external well barrier envelope), casing cement must be verified by logging to ensure a good formation-to-cement-to-casing seal. However, if inner casing is expected to be cemented across the depth where the permanent cement plug (forming an internal well barrier element, WBE) is planned to be set, then the inner casing must be milled so that the outer casing can be logged to verify the barrier seal. Traditional casing milling operations are costly and time consuming, often lasting for several days. This paper describes an alternative way of verifying an external WBE when the inner casing presents an obstruction for outer casing cement evaluation.
Reeder, Stacy Lynn (Schlumberger-Doll Research) | Craddock, Paul R. (Schlumberger-Doll Research) | Rylander, Erik (Schlumberger Oilfield Services) | Pirie, Iain (Schlumberger Oilfield Services) | Lewis, Richard E. (Schlumberger Oilfield Services) | Kausik, Ravinath (Schlumberger-Doll Research) | Kleinberg, Robert L. (Schlumberger-Doll Research) | Yang, Jing (Schlumberger-Doll Research) | Pomerantz, Andrew E. (Schlumberger-Doll Research)
Methods for formation evaluation in unconventional reservoirs are evolving quickly as improved logging methodologies are developed. In gas-producing shale reservoirs, reservoir quality (RQ) is strongly correlated to the total organic carbon (TOC) content, because the kerogen, composed largely of organic carbon, hosts the pore system necessary for storing and transporting gas. In tight-oil formations, however, TOC alone is not as strongly correlated to RQ because storage and transport through inorganic pores can also be significant. Instead, the volume of oil—the only producible organic component in tight-oil plays—is considered a dominant factor impacting RQ, whereas the immobile organic components (kerogen and bitumen) are typically neglected. It has also been argued that immobile components are not inconsequential, but are actually negative RQ indicators in tight-oil plays because they can adsorb oil, swell, and clog pore throats. Indeed, methods to assess RQ in tight-oil formations based on cuttings and core analysis, where the oil content is considered a positive RQ indicator and the immobile organic content is considered a negative RQ indicator, have been proven valuable in many basins, such as the Williston, where the organic-lean middle member of the Bakken formation and Three Forks Formation are generally completed instead of the organic-rich upper and lower members of the Bakken Formation. However, surface measurements alone are inherently limited because the oil content of cuttings and cores from tight-oil formations may be unrepresentative of reservoir conditions due to core alteration, evaporative losses, etc. Here we present a new metric for evaluating RQ in tight-oil formations, the Reservoir Productivity Index (RPI). The RPI accounts for the positive RQ properties of oil and the negative RQ properties of immobile organic carbon, and it avoids challenges regarding representativeness of surface analysis because the oil content and other measurements are based on in-situ logs, principally nuclear magnetic resonance (NMR) and nuclear spectroscopy. A term representing richness is included in the RPI, making a single metric that captures many of the factors describing tight-oil RQ without requiring extensive log interpretation. Several examples of the use of the RPI for evaluating RQ in tight-oil plays are shown.
Sheiretov, Todor (Schlumberger Oilfield Services)
Numerous lessons have been learned from the use of a wide selection of technological elements in the construction of wireline tractors and mechanical services tools. It is well-known that downhole tool design is challenging and requires the use of the latest developments in physics, material science, electronics, mechanical engineering, and software because the tools operate in very harsh environments characterized by extreme pressures, high temperatures, and corrosive fluids. Wireline tractor and mechanical services tools face not only all of these difficulties but also some unique challenges. For example, the tools operate at much higher power levels compared with other wireline tools. The efficient delivery and use of power downhole is an active area of technology development. Another challenge is that the tools interact intensively with the borehole walls or elements of the well completion by exerting very large mechanical forces to tractor along the well, exercise completion elements, mill or cut tubing, remove and collect debris, set or pull plugs, and fish stuck tools. They are also subjected to high shock levels from explosive devices. All of these lead to heavily stressed components. A comparative study has been conducted of a broad range of technologies, from the evaluation of single components such as electric motors to entire systems such as the selection of a drive mechanism, power delivery scheme, or traction control system.
Muñoz, German (Saudi Aramco) | Dhafeeri, Bader (Saudi Aramco) | Saggaf, Hatem (Saudi Aramco) | Shaaban, Hossam (Schlumberger Oilfield Services) | Herrera, Delimar C. (Schlumberger Oilfield Services) | Osman, Ahmed (Schlumberger Oilfield Services) | Otaremwa, Locus (Schlumberger Oilfield Services)
To access the reservoir in a large Saudi Arabian development field, the operator is required to drill an intermediate 5,000 ft to 6,000 ft directional hole section with dogleg severity (DLS) varying from 2.5°/100 ft to 3°/100 ft. The commonly drilled 12¼-in. borehole crosses several interbedded formations comprised of limestone, shale and sands, and it is associated to a variety of hole problems, which present repeatedly in the offset wells. The main objective for the operator was to mitigate the problematic by defining alternative and suited drilling technologies. Among them, Saudi Aramco found that the recent developments in the directional casing while drilling (DCwD) technology may well provide an effective method for diminishing the associated nonproductive time (NPT).
The drilling engineering team conducted an extensive evaluation of the problems across this section, including wellbore stability, water flow, and loss of circulation; tight hole/stuck pipe incidents, severe bit/stabilizer wear while drilling abrasive sands. After a promising technical and engineering evaluation, followed by a detailed risk assessment aiming to determine the potential of the application, the selected well was planned and executed using the DCwD service.
This paper outlines the process carried out during all stages through the final deployment of the first 9?-in. DCwD application in Saudi Arabia, and how it successfully aided in achieving the goals by reducing the impact of some of the problems experienced while drilling the same section in previous wells in the field. Likewise, the information provided will serve as a starting point for the design and construction of subsequent wells leading to further improvement in drilling performance. Best practices and lessons learned from this implementation are expected to become a model and the know-how transferred to other areas where comparable drilling events occur.
The technological benefits have been recognized by the operator and this application reestablished DCwD as a viable technology to address a number of challenges common in many of the Saudi Arabian oil and gas fields.
The Bakken petroleum system (BPS) can be considered a hybrid play because it is composed of both conventional and unconventional elements. The conventional aspects include the presence of separate reservoir intervals (Scallion, Middle Bakken, Sanish and Three Forks) and source-rock intervals (Lower Bakken and Upper Bakken shales) along with more problematic intervals (Basal Bakken). This is in direct contrast to most unconventional shale plays, in which a single lithologic or stratigraphic interval comprises both the source rock and the reservoir. The unconventional aspects of the BPS include very low permeability conventional reservoir sections and combined shale-rich source and reservoir intervals. Additional complexity results from stacked depositional environments with significant variations in lithofacies, mineralogy, total organic carbon (TOC), and rock textures ranging from highly bioturbated to finely laminated.
Based on these complexities, a series of research wells were drilled, cored over the entire BPS, and logged extensively using advanced logging devices. Petrophysical models were developed using both deterministic and probabilistic methods to integrate the measurements acquired for the analysis of porosity, saturation, and mineralogy and for describing the hydrocarbon production potential of the BPS more accurately. The advanced evaluation results will enable us to use these wells as benchmarks and calibration points for computation models being developed in areas of the basin where only minimal logging suites such as triple-combo logs exist as data. The confidence gained from these advanced petrophysical models will ensure that the basinwide models, which encompass the entire BPS, will better represent the actual production results.
Zuo, Julian Y. (Schlumberger) | Gisolf, Adriaan (Schlumberger) | Dumont, Hadrien (Schlumberger) | Dubost, Francois (Schlumberger) | Pfeiffer, Thomas (Schlumberger Oilfield Services) | Wang, Kang (Schlumberger) | Mishra, Vinay K. (Schlumberger) | Chen, Li (Schlumberger) | Mullins, Oliver C. (Schlumberger-Doll Research) | Biagi, Mario (Eni Congo) | Gemelli, Serafino (Eni Congo)
Accurate quantification of oil-based mud (OBM) filtrate contamination of hydrocarbon samples is still one of the biggest challenges in fluid sampling with formation testers. Existing techniques apply only to a very limited combination of probe type and formation fluid type. The methods can be technique sensitive, and lack a confident level of quality control. The technology and variety of downhole fluid analysis (DFA) sensors has evolved greatly over the recent years. However, the methods used to predict contamination have not kept up with the change in technology—until now. The response of multiple sensors has been combined in new methods, new techniques, and new algorithms to significantly improve the prediction accuracy of a fluid sample’s contamination downhole in real time. Results of these new approaches from field studies have been validated against laboratory measurements with good agreement.
Any downhole quantification of hydrocarbon-filtrate content requires knowledge of the properties of a virgin reservoir fluid and pure OBM filtrate. These properties, here referred to as endpoints, cannot be measured directly in most cases. This is the core challenge of real-time OBM contamination monitoring (OCM). Accurate native fluid characterization is the gateway, not only to obtain clean samples, but also to understand fluid-property distributions with confidence in a single well and across the entire reservoir. It is also an enabler for the emerging DFA workflow to use downhole sensor data to characterize the reservoir and the slow dynamic processes that give rise to its fluid distribution.
The mixing rule for optical density has been used for OCM in the past two decades. The assumption has been made that the crude oil is “dark” in an optical color channel where the mud filtrate is assumed “colorless” (coloration is associated with asphaltene content). However, this method is valid only for oil with sufficient asphaltene content in solution (enough optical density in color channels), and it may be erroneous in cases in which the OBM filtrate is not colorless in specified channels or the reservoir fluid does not exhibit color. Moreover, the accuracy of the endpoint characterization is limited if there is no or minimal optical density contrast between the oil and the filtrate. Such lack of contrast in optical density is frequently observed, typically when mud systems absorb color due to well-to-well reuse or if the native fluid lacks color. New physical chemistry-based mixing rules and algorithms have been developed for mass density, optical density, and gas-oil ratio (GOR), and the results are confirmed by laboratory measurements. This novel methodology enables accurate quantification of both the OBM filtrate and the pure virgin formation fluid. The self-consistency of using multiple independent sensors provides confidence and greatly improves the robustness and quality control of OBM-filtrate contamination monitoring downhole. Finally, contamination results can be expressed in volume or weight percent and as live-fluid or stock-tank liquid (oil) fraction for easy comparison to laboratory results.Three field case studies demonstrate the requirements and effectiveness of the new method. A brief description of the formation-testing objectives sets the scene, not only for the contamination monitoring accuracy requirement but also for demonstrating the need to obtain uncontaminated native fluid for determining composition, GOR, live-fluid density, and optical density. Case studies include gas condensate, light oil, and black oil examples, and all results are in good agreement with the results of the laboratory analysis.
We have implemented a targeted ground-penetrating radar (GPR) full-waveform inversion algorithm to quantify the physical characteristics of oil spills under and within sea-ice. We can invert for oil thickness, electric permittivity, and conductivity or any subset of these parameters if the others are known. We tested the algorithm with data collected during a controlled spill experiment at the US Army's Cold Regions Research and Engineering Lab (CRREL). Using 500 MHz radar reflection data, the algorithm recovered the thickness of a5cmthick oil layer to within 8% of the control value. This approach provides a tool for rapid spill detection and mapping that is needed with increasing levels of oil exploration and production in the Arctic environment.
Murray, Douglas R (Schlumberger Oilfield Services) | Belaud, Didier (Schlumberger Middle East) | Ogawa, Ryoko (Schlumberger Middle East) | Shaban, Mohamed (ZADCO) | Edwards, Ewart (Zakum Development Company (ZADCO)) | Abbas, Nashat (ZADCO) | Al Nayadi, Kholoud Ghareed (ZADCO) | Boyd, Douglas Alexander (ZADCO)
A new logging-while-drilling (LWD) sonic tool was successfully deployed in a large development project in the Middle East. The new LWD sonic tool offers robust compressional and shear measurements, irrespective of mud speed, and Stoneley information for a wide range of applications. The acquisition of LWD sonic measurements can be challenging. The introduction of the new tool with a novel hardware design, extensive tool modeling, and an alternative approach to data handling has significantly improved both overall data quality and the viability of advanced answer products while drilling.
The fundamentals of both wireline and LWD sonic measurements are similar; however, differences in the measurements dictated by the deployment environment need to be considered. LWD tools are deployed on a drillstring and have a large diameter. Wireline tools are much smaller and are deployed on wireline after drilling is completed. Operational frequencies, acquired waveform modes, and transmitter-receiver source spacings are also different. The most fundamental difference is that the new LWD tool uses quadrupole technology to acquire shear slownesses in slow formations (shear formation slowness slower than mud speed), whereas, in the same environment, the wireline tool relies on dipole technology.
Although there is considerable literature that discusses waveform quality, processing, and interpretation of wireline sonic measurements, very few such studies exist for LWD sonic measurements. In addition, no studies compare the measurements. To investigate the interpretation and use of the new LWD tool and to compare it with wireline sonic tool technology, both methods were deployed in the same wellbores in a large development project in the Middle East. Most observed disparities were across washed out boreholes where data quality from both wireline and LWD tools was negatively affected by the borehole environment.
Sonic measurements have been around for a long time and have evolved significantly since their introduction in the 1950s. They have applications in a broad spectrum of disciplines including geophysics, petrophysics, geology, geomechanics, completion and reservoir characterization. From the simple applications for correlating surface seismic to borehole logs, the measurements have expanded to provide valuable information about formation lithology, pore fluid, pore pressure, rock strength, borehole stability, formation alteration, cement quality, stress direction and magnitude.
Significant advances in sonic technology have been made on wireline (WL) over the last decades, providing shear and compressional measurements on routine basis, regardless of formation type. Using monopole and dipole sources, wireline tools are capable of measuring shear and compressional slownesses in hard and soft formations irrespective of mud velocity. New generation logging-while-drilling (LWD) sonic tools have appeared, extending the frontiers of acoustics measurements by providing the same measurements for real time informed decisions. The real time data from LWD sonic helps us to analyze borehole stability, compute mud weight windows and casing shoe points and predict pore pressure in addition to the traditional applications of well to seismic tie and formation porosity. These applications, using both real time and memory data, have relied mostly on the measurements of formation compressional due to the difficulty in obtaining shear slowness in the LWD environment, especially in unconsolidated slow formations since the older generation of LWD Monopole tools was limited to providing formation shear slowness in fast formations only.
Even though flow rates of oil, gas and water are the most important parameters of any hydrocarbon exploitation project, only a minor number of wells are permanently connected to a multiphase flow meter (MFM). This method comes with the restriction that only one well at a time can be tested, leading to sparse measurements over the production history of a well. In addition, operating conditions of the test separator can differ from flow line conditions and results in a discrepancy of flow line rates versus test rates. To account for this effect the well-test results have to be reconciled, usually backwards from the sales/export meter to each well.
Bowler, Adam Ian (Schlumberger Oilfield Services) | Logesparan, Lojini (Schlumberger) | Sugiura, Junichi (Schlumberger) | Jeffryes, Benjamin P (Schlumberger) | Harmer, Richard John (Schlumberger) | Ignova, Maja (Schlumberger)
The oil and gas industry has become increasingly interested in drilling dynamics and vibration as causes of drilling inefficiency and reduced drilling performance. Generally, drillstring vibration is measured with shock-and-vibration sensors installed in measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, and rotary steerable systems (RSS). Although these tools provide valuable real-time and recorded-mode information on the dynamic conditions, they are not generally designed to capture continuous high-frequency mechanics and dynamics data, and burst data may miss important information about the evolution of the system response and state.
A downhole mechanics measurement tool has been developed that makes a comprehensive suite of measurements of the drilling process, including forces, accelerations, rotational speed, pressures, and temperatures. In addition to providing information in real-time, the tool has the capability to capture long durations of continuous data at frequencies between 50 and 2,000 Hz. The recorded-mode information obtained has provided significant insight into the response of the drilling system to initiating rotation; drilling procedures and parameter modifications; and exposure to excitation from sources including, but not limited to, rig heave, bottomhole assembly (BHA) component imbalance, and bit-rock interaction. A wide range of occurrences has been captured in which the drilling system switches from a dominant vibration mode, typically torsional (downhole rotation-velocity oscillations or stick/slip) into a different mode, such as axial (bit bounce) or lateral (whirl). Transitions between different types of whirl have also been recorded.
Several cases were studied to investigate the evolution and response of drilling system behavior based on the in-depth interpretation of relatively long durations (minutes to hours) of high-frequency data sets in the operational context. The findings verify the value of using continuous high-frequency vibration data to understand the drilling system and increase drilling performance.
It is well known that drilling dynamics and vibration are a major cause of bit and bottomhole assembly (BHA) damage and reduced drilling performance. Lost productivity and increased drilling cost due to failures caused by downhole dynamics drives continuing research in this area. Within this particular service company, operations failures related to shock and vibration generated hundreds of millions of dollars in loss in 2012, representing more than one quarter of the total loss reported.
Downhole dynamics has been a subject of an intensive research using various downhole sensors and instruments in the past decades. Different BHA whirl types have been identified using transverse bending-moment sensors and transverse magnetometers (Close et al. 1988; Shyu 1989; Vandiver et al. 1990; Macpherson et al. 2001). Other researchers have used two sets of accelerometers in a rotary steerable system (RSS) to detect and quantify collar/stabilizer whirl (Minett-Smith et al. 2010). Using the same sensor, Stroud et al (2011) showed the motion of the collar in transition from “rolling-sliding” to “backward whirl” in laboratory testing.