A new azimuthal electromagnetic (EM) logging-while-drilling (LWD) tool has been developed with multiple tilted antennas to measure three-dimensional (3D) electromagnetic fields. Multiple field trials successfully demonstrated the ultradeep detection range of more than 200 ft (60 m) with various transmitter-to-receiver spacings and operating frequencies, providing valuable geomapping insight for large-scale reservoir development. Additionally, this paper reveals the tool's capabilities in different geosteering applications, requiring different depth of detection (DOD) ranges for landing a well, optimizing well placement in thin reservoirs, and eliminating the need for a pilot hole.
This paper discusses in detail a new 3D finite-difference (FD) method to simulate realistic and complicated formation structures in three dimensions, enabling accurate formation interpretations and inversion of reservoir geology. Solving the scattered potential boundary value problem with the 3DFD numerical algorithm simulates the EM signals in this new LWD ultradeep application, and the modeling accuracy was benchmarked alongside in-house modeling codes and 3D commercial software. To accelerate the computation in the 3D modeling, sliding window, multicore parallel cloud computing, and decoupling between model pixel grid and FD simulation grid have been implemented for practical applications. Additionally, 3D modeling is used in the inversion to provide more accurate and complex reservoir determinations.
In addition to inversion, the tool provides 3D azimuthal multispacing, multifrequency geosignal, and resistivity measurements. Using the inversions and the 3D azimuthal images of the geosignal and resistivities enable improved reservoir understanding and geosteering decisions for the three dimensions. This paper describes two field trials from relatively thin to thick reservoirs to establish great and flexible geosteering performance because of multispacing, multifrequency measurements, and a robust signal and inversion process to optimize wellbore placements in the reservoir.
Technological advances are enabling the completion phase of well construction to evolve from interpreting surface-measured pressure and load charts to more direct communication for determining downhole activity and wellbore conditions. Bi-directional acoustic telemetry provides a method for communicating with downhole tools in real-time, where commands can be given to trigger an operational activity in lieu of traditional mechanical means, such as dropping a ball and building pressure, and in addition receive feedback that the activity has occurred.
While current completion methods have been successful using pressure and applied mechanical loads to actuate tools, there are certain scenarios where operations are difficult to execute and it can be challenging to confirm that a piece of equipment has functioned as desired. There are environmental conditions, such as high deviations and s-shaped wellbore geometry, which can be prohibitive to tasks such as getting an activating ball to gravitate to bottom and land on its seat. Using bi-directional acoustic telemetry can eliminate the need for these manual manipulations.
The aforementioned scenario has long been an issue for wells requiring sand control where the completion design might dictate deploying screens into an openhole horizontal wellbore section, performing a gravel pack for wellbore stability, and reducing the production of fines. With the growth of Extended Reach Drilling (ERD), this problem has become more common. This paper discusses adoption of proven bi-directional acoustic telemetry as a method to reduce completion time and remove some of the uncertainty in completing a well. The signal can be transmitted through the drillpipe by use of repeaters that allow for communication to extended depths. When setting a packer, receipt of the command at the hydrostatically operated setting tool triggers the setting tool to function. As a result, the packer at the top of the lower completion sets and the screens become anchored at the desired location. Bi-directional communication allows for confirmation at the surface that the signal was received and the tool properly triggered. This telemetry can further be used during the gravel packing operations to get near real-time temperature and pressure readings from washpipe gauges housed within the screen assembly.
The example documented in this paper is a novel method of deploying a gravel pack system with a bi-directional, acoustic through pipe telemetry within completion tools now in development. This method provides a platform for real-time control and monitoring in the completion environment.
Drilling activities in the oil and gas industry have been reported over decades for thousands of wells on a daily basis, yet little effort was made to analyze this text in large-scale for information retrieval, sequence mining, and pattern analysis. Drilling reports contain interpretations written by drillers from noting measurements in downhole sensors and surface equipment, and can be used for operation optimization and accident mitigation. In this initial work, a methodology is proposed for automatic classification of sentences written in drilling reports into three relevant labels (EVENT, SYMPTOM, and ACTION) for hundreds of wells in an actual field. Some of the main challenges in the text corpus were overcome, which include the high frequency of technical symbols, mistyping/abbreviation of technical terms, and the presence of incomplete sentences in the drilling reports. This work describes state-of-the-art classification accuracy obtained within this technical language and illustrates advanced queries enabled by the tool.
A new electronic sliding sleeve has been developed for hydraulic fracturing that provides the operational efficiency of sliding sleeves while enabling an unlimited number of fracturing zones and eliminating the milling of the baffle seat. This system uses electronic sensors and battery power to determine when the next stage of the fracture is ready for pumping. The reliability of the sensors, electronics, and batteries must be addressed to achieve a reliable fracturing system.
Traditional sliding sleeves use a series of progressively smaller-sized balls that shift sleeves by landing on progressively smaller-sized baffles. The new electronic sliding sleeve has the intelligence to enable opening the sleeve without the use of progressively sized balls and baffles. The result is a monobore construction that enables stimulating an unlimited number of zones and simplifies well completion design and installation. The electronic implementation improves the mechanical reliability beyond mechanical monobore fracturing tools but introduces other concerns of reliability. This paper reports on the reliability testing of the electrical components including the electronics, sensor, and battery.
Electrical reliability of the new sliding sleeve was evaluated at high temperature, extended service duration, and high pump rates. The sleeve operates by counting the passage of frac balls and then shifting the sleeve when the programmed number of balls has passed. This battery-powered electronic sliding sleeve has an onboard sensor and processor equipped to count the balls. Once the programmed number of balls has been detected, an actuator commands the sleeve to shift. The sliding sleeve requires reliable operation of all components. A probabilistic model is used to account for stochastic variation in batteries and electronics. The magnetic sensors detected the frac ball over a wide temperature range and at flow rates ranging from near static to more than 100 bbl/min. The batteries were characterized for operating life, passivation, and self-discharge. Power consumption and reliability of the electronics were tested to accurately predict remaining operational life of the electronic system under a wide range of conditions. The resulting electronic sliding sleeve also increases mechanical reliability.
A programmable battery-powered electronic sliding sleeve increases flexibility, reliability, mechanical simplicity, and robustness for multistage hydraulic fracturing. This new fracturing system is particularly applicable in extended reach applications by offering an unlimited number of zones with a simple monobore construction.
Arackakudiyil Suresh, Zac (Halliburton) | Kumar, Ajit (Halliburton) | Rondon, Leonque (Halliburton) | Pingle, Darshan (Kuwait Oil Company) | Al-Hindi, Khaled (Kuwait Oil Company) | Boushahri, Mohammed (Kuwait Oil Company)
Multilateral intelligent wells have been proven effective by both extending reservoir contact and providing proactive reservoir management. This paper highlights the lessons learned and critical well construction and completion steps that improve the efficiency of intelligent multilateral well drilling and completions operations. The case study outlines the successful completion of the third multilateral intelligent well in the Minagish field of West Kuwait.
The intelligent level 4 multilateral well was designed and drilled successfully. The sidetrack was performed using a specialized latch coupling that allowed for multilateral window cutting, orienting, and re-entry. The latch coupling was run in hole with the main bore casing, and a key orienting tool was used to confirm its orientation. Once the main bore was complete, a window was cut using a dedicated milling machine. Thereafter, a drilling whipstock was run with a window mill and watermelon mill to allow access to the lateral. This was followed by drilling the lateral section and running and cementing the liner. After the lateral section was drilled to the planned depth and cleaned out, the whipstock was retrieved. The intelligent completion installation consisted of a lubricator valve, two downhole permanent gauges, and two variable choke interval control valves.
The presence of surface-controlled, variable choke valves to control inflow from both the main bore and the lateral provides the capability to effectively manage the reservoir and production over the life of the well. This, in turn, prolongs the field life, thus improving overall economic performance and field economics. The case study well is the third multilateral intelligent well installed in Kuwait, and many recommended practices were implemented that allowed for improved efficiency and safety of the operation. Maintaining a clean well was emphasized as a top priority throughout the well construction process. The cement curing time was increased and the completion string was reviewed and redesigned.
This paper discusses the lessons learned and improvements made during installation of the third multilateral intelligent well. The steps performed during this operation have become the recommended practices for all upcoming intelligent multilateral well operations in Kuwait.
A new wireline nuclear magnetic resonance (NMR) logging tool is capable of providing high-resolution logs at a logging speed that is twice that of the typical current MRIL® tool logging speeds. The new sensor features a stronger magnetic gradient to enhance the sensitivity of diffusion-based fluid typing; it also provides a much shorter inter-echo spacing (Te) to increase the data density per echo train. Consequently, the new sensor reduces the requirement of vertical averaging, which enhances the resolution of thin bed formation evaluation.
The new NMR sensor addresses industry requirements for reliable porosity, organic vs. intergranular porosity discrimination, and free vs. adsorbed fluid fractions in low porosity, heterogeneous unconventional reservoir evaluations. The paper discusses optimization aspects of the sensor, including antenna aperture, maximized packing density of frequency bandwidth, and multi-frequency short inter-echo spacings. The new NMR sensor is fully combinable with several nuclear, electromagnetic (EM), and acoustic logging instruments with a log vertical resolution that is comparable to that of wireline density logs.
Field tests from North American unconventional wells have demonstrated that only minimal stacking is needed to meet the 1 PU porosity repeatability and moderate stacking for reliable fluid typing, even in low porosity unconventional reservoirs. With an optimal number of frequencies used for unconventional reservoir applications, an advantage is realized from the total frequency bandwidth for optimal signal-to-noise ratio (SNR). The optimized SNR, in addition to the short Te, also improves the 1D T2 spectral and 2D map resolution and, consequently, free light hydrocarbon and organic pore fluids. Intergranular fluid signals are also resolved in several wells with porosity as low as ≤ 5 PU.
Mud filtrate invasion occurs in the immediate vicinity of the well as a result of the overbalance pressure of the mud column in the well. Oil-based muds (OBM), unlike water-based muds (WBM), are miscible with reservoir fluid, and OBM contamination alters the properties of the original formation fluid. The bubblepoint of contaminated fluid is usually lower than clean fluid. While fluid is pumped out of the formation, it becomes cleaner and the bubblepoint increases; the upper limit of the increase is the clean formation fluid. While increasing the pumping rate can shorten cleanup time, pumping below the bubblepoint can modify the fluid phase behavior and cause asphaltene content in the formation fluid to precipitate out and sensor data to become erratic and noisy. Therefore, it is important not to pump below the bubblepoint, knowing the clean fluid bubblepoint in real time provides a guideline for the field engineer. The purpose of fluid sampling is to collect a representative formation fluid—samples with an acceptably low contamination. The clean fluid bubblepoint provides a lower limit on pumping pressure, which helps ensure pumping does not go below the bubblepoint and the sample is in single phase.
This paper describes how clean fluid compositions are determined from the asymptote of the principal component analysis (PCA) reconstructed scores and then used as input for the equation of state (EOS) program to compute fluid properties such as bubblepoint and gas/oil ratio (GOR). The optical spectral data from the optical fluid analyzer is first despiked, and outliers from the despiked data are removed using the robust ordinary least squares regression (ROLSR) method and robust PCA (RPCA). After removing outliers, clean fluid spectra data are reconstructed using asymptotic PCA scores and PCA loadings. Using a neural network model, clean fluid compositions are determined from reconstructed fluid spectral data, and fluid compositions are used as input for the EOS program to determine fluid properties.
Results confirm that the clean fluid bubblepoint and GOR do not change significantly after a few tens of liters of fluid pumpout. Analysis of the first principal component (PC1) confirms that most of the variations occur during the first few tens of liters of pumpout, indicating the predicted clean fluid compositions and properties are somewhat stable. This approach can help determine the clean fluid properties, even while pumping before taking the sample, helping ensure a monophasic fluid sample. When pumpout accumulated volume reaches 40 to 50 L—within 15 to 20 min of pumping out contaminated fluid—clean fluid compositions and properties can be estimated and used to determine reservoir continuity. Additionally, knowing the clean reservoir GOR and API gravity can help determine the type of reservoir fluid in real time.
Operators often use real-time operation centers (RTOC) as a funnel point for data streams transmitted from multiple rigs during the well construction process. A RTOC is typically staffed by subject matter experts (SMEs), with the primary goals of interpreting real-time wellbore conditions and relaying actionable recommendations to help reduce nonproductive time (NPT) and well control incidents.
Automation is a strong industry trend. Autonomous systems are being developed to flag potential NPT events before they occur; however, these systems are not yet widely used. In the absence of these systems, workflows among complementary disciplines have been developed to identify potential NPT events in large data streams transmitted to a RTOC. This paper presents example scenarios from deepwater prospects with potential actionable recommendations.
Robust data streams transmitted to a RTOC can be received by the overlapping disciplines of hydraulics optimization, drilling optimization, and geomechanics. Staff from each discipline filter through the raw data to capture incoming information relevant to their respective output analysis. A key goal of each discipline is to mitigate the risk of NPT through real-time identification of warning trends observed during deepwater drilling in narrow pressure window situations. The multidisciplinary overlapping efforts produce a process that is much more effective than is possible with each discipline operating independently. Because real-time geomechanics seeks to update the bounding conditions of the downhole pressure operating windows, collaborative workflows are structured around validation and calibration of the real-time geomechanical model.
Collaborative workflows are presented for specific operations during the well construction process in which NPT events are likely to occur, such as tripping out of the hole and drilling. In the examples, real-time calculated equivalent circulating density (ECD) models, hole cleaning parameters, swab pressure models, and torque/drag plots provide input to the real-time geomechanical model. Outputs of this analysis are actionable recommendations, such as an extended flow check, check trip, or mud weight increase. The workflows were developed based on lessons learned from information in a central database and the resulting best practices from multiple deepwater wells.
Decision makers are provided with data-supported recommendations at crucial junctures; these recommendations typically involve costly rig time. The trade-off between increased rig time and benefits gained from the recommendation is difficult to quantify. The workflows derived from a library of NPT events address the perception of wasted rig time and provide context to real-time interpretations. Combined plots supporting the recommendation provide confidence for the driller that the increased rig time is time justified.
Continuous circulation technology is used to maintain constant circulation of drilling fluid in a well by enabling the rig pumps to remain on during all steps of the drillpipe connection process. Continuous circulation is a managed pressure drilling (MPD) technique; it improves drilling success for difficult high-pressure high-temperature (HPHT), narrow pore pressure/fracture gradient, and extended reach horizontal wells.
Traditionally, a continuous circulation system relies on a manifold connected into the rig standpipe, which diverts flow to and from the topdrive to a side port on a sub that is threaded into the top of each drilling stand. Historically, this side port flowline is connected manually by an operator, within the rig floor red zone, in a single barrier pressure environment. To enhance safety by removing exposure to any single barrier pressure applications, a new system was developed that automates and enhances the current manual process.
The automated continuous circulation system includes a connection tool that is mounted on a manipulator arm; after it is delivered to the drillstring and clamped, it will use a human machine interface (HMI) to automatically and remotely remove a threaded side port safety cap, connect the side port flowline, and control the manifold flow diversion process. The system is controlled at the HMI by an advanced software system that is capable of functioning autonomously, with operator verification steps. Internal robotic mechanisms drive the system to perform the exact steps as a human without requiring modifications to the proven continuous ciruclation sub design, all while providing instantaneous feedback to the operator located at the remote HMI.
A prototype tool was assembled and successfully tested in November 2016 in the Val D'Agri oilfield region in southern Italy. With a rapid technical development cycle of less than one year in a down market, a commercial tool was developed and deployed, including the implementation of all lessons learned. This system is the first in the industry to provide threaded engagement of the side port flowline, and a successful undermount delivery arm. This paper presents results from more than 1,000 diversion connections in both laboratory and field environments.
With a 10-year track history of the manual system, the automated system enables the operator to improve upon proven technology to safely deploy continuous circulation capabilities in offshoreapplications, from fixed platforms to floaters, in areas with strict industry certification regulations, personnel in red zone limitations, and double pressure barrier requirements. The system reduces overall added connection time from typical manual systems, increases safety, and maintains the benefits of continuous circulation to reduce nonproductive time (NPT) and total drilling days.
Hassi Messaoud (HMD) is a mature oil field with approximately 1100 production wells. About half of the wells are natural flow and the other half are continuously gas lifted (CGL) with concentric (CCE) strings. CCE gas lift is different from conventional gas lift as the lift gas is injected in the well through the CCE string while production is from the annulus between the CCE string and the tubing. The typical production tubing size is 4 ½". The sizes of the CCE strings include 1.315", 1.66", and 1.9". The 1.66" CCE is most commonly used in gas lift wells. The typical gas lift injection line on the surface is 2" from the gas network to the wellhead. A choke is used on the gas lift line to control the lift gas injected into each well. As the injection gas pressure is high from the source of available lift gas, large pressure drops across the lift gas injection chokes exist in some wells. Due to the Joule-Thompson effects, a big temperature drop is associated with the large pressure drop across the lift gas injection choke. This temperature drop can result in hydrate formation in the lift gas line downstream of the gas lift choke. Hydrate formation in the gas injection lines, especially in winter has seriously disrupted production due to plugging of lift gas lines.
Salt deposition is a big challenge in Hassi Messaoud field operation. The reservoir interstitial water contains high salt concentration in excess of 300 g/l. During well production, salt deposits in the wellbore and across the production choke. Periodically, water is required to be injected into the well to dissolve the salt and restore well productivity. A CCE string allows water to be injected into the wellbore either concurrently with injection lift gas or separately by itself for a specific period of time.
High volumes of lift gas are injected in many wells due to the lack of effective control in the lift gas injection rates. The excessive gas from lift gas injection and production in the system can lead to the need to flare occasionally when the facility gas capacity limit is exceeded.
In order to reduce the usage of the high volume of lift gas, Intermittent Gas Lift (IGL) was selected in a pilot project to evaluate its applicability in the Hassi Messaoud field.
Three CGL wells were selected for this pilot project. The selected wells are characterized by high GOR, low PI and without continuous concurrent water injection (with lift gas) to dissolve salt deposited down-hole.
IGL operation parameters were designed by using modified empirical correlations to those presented in the API Recommended Practice for Intermittent Gas Lift. The modifications were suited for the operating conditions in Hassi Messaoud Field. Static and dynamic well and network models were created to simulate the field test results and guide new designs and future applications.
This paper presents the pilot test programs and the results from this project in mitigating both the excessive lift gas injection problem and injection line blockage due to hydrate by converting certain CGL wells to IGL. It also highlights the application conditions for the future. Finally, the plan for the expanded application of IGL in Hassi Messaoud is discussed.