Bone, Glenn (Apache Corp) | Jamerson, Christopher (Apache Corp) | Klassen, Jay (Schlumberger) | Gray, Jordan (Schlumberger) | Valliyappan, Somasundaram (Schlumberger) | Baker, Ryan (Schlumberger) | Turner, Kerry (Schlumberger) | Parra, Miguel (Schlumberger)
Inconsistent roller cone/PDC bit performance drilling horizontally through the hard/abrasive Granite Wash reservoir in western Oklahoma has resulted in low ROP, increased operating days, and escalating drilling costs. The difficult Marmaton age wash formation is encountered at 11,000-13,000ft TVD and has unconfined compressive strength (UCS) in excess of 30,000 psi. The typical well requires drilling a curve to horizontal, then 4,000 ft of 6-1/8-in lateral borehole. Offsets analysis revealed that 1-4 RC/PDC bits are required to drill the curve in addition to 1-13 bits to finish the lateral. The operator required a technological solution to minimize bit consumption/trips to lower well construction costs while achieving directional requirements.
An analysis of the most troublesome wells was conducted and a mathematical-based predictive analysis software identified the changes required to efficiently deliver the directional objectives. The study indicated that using a 4¾-in high-power steerable turbodrill, with two bends and a specific stabilization setup coupled with an application-specific 6 1/8-in diamond impregnated bit would significantly increase BHA performance and enhance section economics. The operator's drilling team studied the recommendation and concluded the BHA had the potential to increase reliability and reduce operating costs drilling the difficult Marmaton Wash.
This new turbodrill/impregnated bit BHA was run in several Washita and Beckham County wells with outstanding results. In one well the BHA drilled 4,040ft of 6 1/8-in lateral hole section in a single-run saving the operator eight drilling days and $348,000USD vs plan. The assembly required steering only 17% of the time. The borehole was completed in 589hrs at an average ROP of 6.9ft/hr. This performance set several new world drilling records. The authors will present case histories that illustrate performance achievements in the horizontal section and provide details that contributed to the success of the unique BHA.
Managed Pressure Drilling (MPD) has gained industry-wide acceptance as a technology that enables drilling into the challenging zones. Narrow pore pressure - fracture pressure window, depleted reservoir zones, highly fractured reservoirs and deep-water wells are few examples of such challenges. Weatherford's MPD system has proved its effective application in drilling challenging wells. Its unique early kick and loss detection software capability helps to identify such event in very early stage, take corrective action and hence to minimize the nonproductive time. Early detection of a kick / loss event helps in minimizing the potential risk posed by the event and ensure safety during the operations.
Weatherford's advanced gas extraction and analysis system uses an innovative membrane technology and high speed gas chromatograph to improve surface gas detection and analysis in real time. This capability was utilized in conjunction with accurate flow metering capability of MPD system. Various tests were carried out to validate the advanced gas detection system's capability to detect and analyze gas in mud. During circulation of the influx, data from gas detection system helped to plan the strategy gas on the surface. The test data was validated by the data from real wells.
Feedback from the advanced gas detection system also helped to control the break out of the dissolved gas from oil based mud by varying surface back pressure through automated chokes. This is very critical to ensure that gases containing hydrocarbons are handled safely on the surface. It also provided quantitative analysis of the lighter and hence volatile hydrocarbon components. Circulation rates and surface back pressure can be used to mitigate potential hazards. Use of advanced gas extraction system in combination with MPD system added significant HSE value by making well control operations more efficient and safer.
During operations in deepwater wells (such as, for instance, running smart completions), there exist periods when the axial movement of the string in the well remains uncompensated. During these periods, vessel heave is imposed on the string at the surface, resulting in transient pressure fluctuations (swab and surge effects) in the fluid downhole. The problem is further complicated by the presence of multiple flow ports in the string, and of choke and kill lines at surface, as well as float valves in the string itself. As the margin between pore and fracture pressure is narrow, these fluctuations can create conditions for an influx or lost circulation, with potentially significant consequences. While existing literature and commercial models address the classical drill pipe induced swab/surge due to tripping, they do not model multiple flow paths and/or continuous forcing functions (such as heave) at the surface of the drill string or completion string.
In this paper, we present the development of a semi-analytical approach to model such transient pressure problems. The transient pressure problem is solved using the method of characteristics, and draws from the seminal work of Lubinski et al. and employs the electrical analogy first proposed by Bergeron (Water hammer in Hydraulics and Wave Surges in Electricity", John Wiley, 1961). The method is extended to include Power-Law fluids (as well as Bingham Plastic and Newtonian rheological models). Arbitrary flow ports can be situated anywhere in the string, with either one or two-way flow. Both open- and closed-end pipes are considered, in addition to nozzles at the pipe end. Temperature and pressure effects on the compressibility, as well as the elasticity of the formation, are considered in the calculation of the characteristic impedance. The approach can accept any arbitrary forcing function at surface, either as a periodic wave or as a tabulated time function of displacements. Several limitations of the previous models are also addressed in the theoretical development reported in this work.
The method is implemented in a spreadsheet tool that allows the input of a wide variety of situations, incorporates different fluid PVT and rheology models, and calculates transient pressure at any point of interest in the annulus. The model is compared to several benchmark field cases in the literature, and the comparison is shown to be very satisfactory. Finally, a case of a smart completion with one to four flow ports in the lower sections that can be selectively closed or opened, subjected to sinusoidal vessel heave at surface, is examined. Results show that the pressure fluctuations can be substantial in some of the cases, and suggest that with appropriate fluid selection and operational procedure, even large heave can be sustained without initiating either underbalance or lost circulation.
Hole enlargement using underreamers has become a necessary drilling practice in deepwater Gulf of Mexico. Underreaming while drilling saves operators an extra trip to open a hole, and improves drilling budgets. Further benefits include better equivalent circulating density management and optimal cement jobs because of the bigger annulus. With these benefits come great challenges that can be categorized into three classes: 1) Drilling dynamics 2) Drilling performance and 3) Hole quality. These challenges, if not addressed during the planning and execution phase, can lead to tool failure, lower penetration rates, and hole angle deflection. This paper presents a deepwater Gulf of Mexico success story where a total systems optimization approach was utilized to overcome the previously mentioned challenges, generating a scalable improvement in drilling efficiency.
This paper presents the planning and results from two sections of the subject well - 18 1/8 x 21 in. and 16 ½ x 19 in. Each section had different sets of challenges. The first section was drilled through an inter-bedded formation entering at the top of the salt, while the second section was drilled entirely in salt. To overcome these challenges, an optimization approach was followed, which consisted of four steps - 1) Offset well analysis 2) Bit/underreamer selection 3) Development of optimum drilling parameters and 4) Roadmap to manage these parameters on the rig.
According to field results, this approach improved the ROP by more than 15% in the 18 1/8 x 21-in. salt section. Drilling efficiency for both sections was enhanced by more than 65% when compared to previous offsets. For both sections, the maximum hole inclination was 0.13° or less, keeping the well vertical. Furthermore, lower axial and lateral vibrations were observed, eliminating downhole tool failures while the bit and underreamer came out with better dull conditions compared to the offsets.
Since the late 1990s, remote operations centers have focused on infrastructure and remote data gathering as some of the key resources in the intelligent oil field. Data gathering has low direct value unless used to mitigate risk and enhance operational efficiency. Rigsite experts work under the framework of health safety and environment (HS&E) and operational progress, with limited ability to analyze data. There is limited value in data gathering without real-time analysis of the information. This analysis is becoming one of the most important factors of daily work in remote operations centers. Real-time analysis is performed by multi-disciplinary teams, and remedial action can be taken immediately to mitigate risk. This is the strength and force of the operational centers; available interpretation technologies and time to perform the tasks in an environment without the rigsite stress factors.
During traditional operations, the wellsite personnel are responsible for the well and for ensuring nothing hazardous occurs, or taking action before or after an unwanted occurrence. In many cases, this is too late. Operations center planning, modeling and analysis - to avoid unwanted situations - are all part of the operational procedure, providing trends and thresholds for procedure change prior to an incident.
The wellsite personnel determine indications of well instability with potential to lead to extensive use of resources to ensure stable conditions. This is often based on experience and local knowledge.
The onshore team focuses on proactive processes to ensure the overall operational progress is conducted in a safe manner.
To illustrate data gathering and risk mitigation of a remote operational center, the BEACON center concept is used to display rigsite workflow, data analysis and feedback for maximum progress and minimum risk. Subsurface knowledge through drilling optimization and BHA reliability will be covered.
The current paper represents an overview of the automation model for drilling fluid mixing and is based on thesis works of (Nafikov 2011) and (Glomstad 2012).
The first part of investigation is based on a model developed with the help of MATLAB® and SIMULINK® softwares. The simplified mud circulation model consists of downhole and mud mixing systems. The well is divided into control volumes to imitate the moving of drilling fluid inside the drillstring and the annulus and to include disturbances such as production of cuttings and mud losses to the formation. The possibility of monitoring the downhole pressure is included as well. Mud mixing system is represented in a way of addition of chemicals for mud treatment, i.e. viscosifier (bentonite), densifier (barite) and the mud dilution property with the help of water addition. The addition of all chemicals is controlled by PID controllers. Mud mixing and downhole systems interact between each other during simulations. When fluctuations in a form of cuttings or mud losses occur in the dowhole system, the mud mixing system adapts all PID controllers to keep the desired mud properties. The performance of the model is shown in the case of closed-loop simulations. Obtained results show the expected behavior of all variables and the possibility of automatic control.
The second part of investigation will look at two principles for control of the mud mixing: cascade control and model predictive control. Compared to conventional PID-controllers with a single feedback loop, the cascade structure can utilize measurements both in the mixing tank and where the mud flows out of the well together. Continuous measuring of the mud properties is assumed. Also a controller based on model predictive control has been designed and tuned by using SEPTIC, an MPC tool developed by Statoil. The MPC controller calculates optimal inputs by minimizing a cost function subject to process constraints, defined priority levels and deviation penalties. Calculations are based on density and viscosity models found by looking at open-loop simulations of system responses to a change in different input variables. Closed loop simulations have been performed using both MPC and cascade controllers. A model for the well, ??WeMod??, is provided by IRIS and simulates the behavior of an actual well so it is seen how downhole conditions influence the density of the mud.
Microhole coiled tubing drilling is a new technology that provides many added advantages but at the same time poses numerous operational challenges. This manifests itself in a number of ways, all of which adversely affect the efficiency of the drilling process. These problems include increased wellbore friction, poor hole-cleaning, tubular failures, and associated problems during tripping operations. Presently conventional torque and drag models are used to calculate drag forces and surface loads during microhole coiled tubing drilling. However, these estimates might be under conservative. Therefore, an improved model and more comprehensive analysis are required.
Conditions expected during microhole coiled tubing drilling are completely different from those encountered during conventional drilling. Further complexity is added when the wellbore is undulated. This paper describes a new analytical model for estimating drag forces by assuming that pipe in the horizontal portion follows a sine function wave due to residual bends and snubbing force. In addition, the model takes into account when the wellbore is also tortuous. Fluid viscosity (an important force in the microhole) is also included so we can calculate appropriate surface loads in addition to drag. This study concludes that besides wellbore inclination, curvature, and wellbore torsion, parameters such as wave length and contact area also influence the results. This paper documents the comparison between the predicted mathematical simulation results with actual data from wells describing the accuracy and applicability of the model. The analysis results and comparison are presented along with three examples.
Negative pressure tests are an important step in proving well integrity for some well operations. Although the concept is straightforward, there are no standard procedures for conducting and interpreting negative tests. Recent industry experience has shown the potential for these tests to be misinterpreted with disastrous results. This paper describes proper quantitative interpretation of both successful and unsuccessful tests demonstrated on two full-scale test wells.
Tests with and without water leaks are simulated in two vertical wells with 2971ft and 5884ft depths. Test results are interpreted quantitatively to distinguish successes from failures. In addition, the impact of leak rate and the differential pressure between the leak source and well are investigated. The impacts of gas as a leak fluid, different well volumes, different surface piping arrangements, and different measuring tanks are also shown.
The success of a test should be verified with both flow and pressure checks. For the flow check, a trend between bleed off pressure and volume can be predicted based on fluid compressibility, tubing expansion, and drainage from surface piping. Deviations from that trend will identify the onset of a leak. Early detection and control of a high rate leak can reduce the formation fluid volume entering the well and the consequent risks. Detecting a low rate leak is difficult if the test duration is too short. Therefore, a 30 minute test duration was evaluated for detection of low rate leaks.
The fundamental differences between a leak and no leak are conclusively demonstrated with quantitative results. Approaches for overcoming complications to achieving conclusive tests are explained and demonstrated. These test results and the proposed interpretation methods are applicable to vertical wells. Drilling fluid properties, multiple fluids, and thermal expansion can also influence results but were not investigated in this study. Nevertheless, these results should provide a basis for improving field procedures and minimizing the risk of misinterpreting a leak as a successful test.
Value-added efforts towards determining the optimum approach to drilling challenging offshore prospects include applications of reliability centered strategy early in the planning process. The objective would be to determine the drilling method with highest probability of enabling a safe, on-time and on-budget drilling program that reaches total depth objective with large enough hole for viable production.
Reliability assessments focus on probability of successful functioning; fit for a purpose, resistance to failure, ability to perform a required function for a definitive period of time, and ability to fail well. The reliable performance of the hydraulics of the circulating fluids system itself, even if the encountered pressure environment is not within the predicted drilling margin of error, is critical for operational success.
This presentation applies Reliability Engineering skills to a HPHT prospect whose water depth and formation pressure map suggests risk of kick-loss scenarios, differential sticking, cementing challenges and TD with too small a hole. An offset well's actual experience with conventional drilling methods will be compared with an operational reliability assessment of applying some applicable variation of managed pressure drilling (MPD) on the proposed well.
Reliability theory became a creditable science during the early days of sail ships to inform investors of the reliability of a vessel to return safe & sound.1 The author proposes that operational reliability concepts remain valuable in marine environments and are uniquely applicable for the purpose of choosing the optimum drilling and well construction methods for drilling challenging offshore drilling programs.
Conventional well control procedures rely merely on the pit gain and variations in pump pressure as the primary indicators to detect and handle the influx. These indicators are rudimentary and unreliable for drilling costly offshore wells while advanced well control techniques demand more reliable indicators for early detection of gas kicks. Having access to continuous pressure data along the wellbore, offered by intelligent (wired) drillpipes, can be very helpful in detecting and handling gas kicks.
This paper proposes a technique for early gas detection during conventional drilling by utilizing the intelligent drill pipe. For this purpose, different flow regions in the annulus are identified and modeled based on the conservation equations. A numerical scheme and transient gas kick simulator are developed to solve the equations. Sensitivity analysis is conducted for various parameters such as influx sizes, mud flow rates and wellbore geometry.
The results indicate that when gas influx enters the wellbore, pressure at all sensors increases simultaneously. This criterion can be used for early detection of gas kicks; In addition, when top of gas influx passes a certain sensor, pressure curve at that sensor declines. This fingerprint can be utilized in determining the location of the gas kick. This can be done even more precisely when pressure derivative curves are plotted to determine the time that a gas influx reaches a certain sensor.
Using intelligent drill pipes in modern well control operations can reduce kick detection time to less than half, which results in significant reduction in non-productive time and enhancements in safety. The developed simulator provides a powerful tool that can contribute to well control practices and real-time decision making.