The digital transformation of the oil and gas industry is happening right now. This session looks at how digitalisation and data sharing philosophies can change business models, as well as enable optimised operations and efficiency gains through better insight, faster decisions and optimised work processes. The progress of drilling technology is exposed widely in this section. Scientists and engineers from academia, oil companies and service companies are working together to develop new methodology and experiences. The session includes Depletion and Re-Pressurizationin the Valhall Field, Reconstruction of Pipe Movement, Optimized Trajectory and Efficient Slot Recovery, Model Parameters on Frictional Pressure Loss Uncertainty and Accuracy of Combining Overlapping Wellbore Surveys.
The effects of horizontal well geometry remain debatable in most production modeling works. Most of recent reports fail to mention the effects of well geometries, especially in severe slugging cases. This study presents a qualitative comparison between different well geometries and their impacts in production performance of horizontal wells.
The study utilizes a transient multiphase simulator to mimic the production from a horizontal well over a 12-hour period. The well has a 2-7/8″ ID tubing with TVD of approximately 5000 ft and MD of 10000 ft and maximum inclination angle of 10º within the horizontal section. The trajectories of horizontal section in the well include 5 cases, 5 undulations, hump (one undulation upward), sump (one undulation downward), toe-up and toe-down. These configurations are the representative examples of horizontal wells. A reservoir with a given deliverability equation and several perforation stages is used to provide well inflow. The impacts of reservoir deliverability, GOR, pressure and temperature are studied for all well geometries.
The simulation results offer some valuable insights into the effects of well trajectory on production performance, including borehole pressure profile, liquid holdup, gas and liquid rate variations with time, and cumulative gas and liquid production. At high production rates, severe slugging is not observed, and thus, the well geometry effects are minimized with a consistent production at the surface. However, toe-up configuration exhibits a slightly better performance than the others.
As the productivity and pressure reduces throughout the life of a well, the impacts of well trajectories become clearer. The presence of severe slugs and blockage of perforations near the toes causes a noticeable drop in production. During severe slugging, the pressure profile reveals longer fluctuation cycles, resulting in extreme separator flooding issues. The slugging frequencies are compared among different well geometries. Toe-down case exhibits lower slugging severity. As a result, toe-down well produces the highest cumulative liquid and gas rates. The presence of liquid blockage is observed in lateral and curvature sections. The toe-up and hump configurations exhibit the most severe slugs with minimum cumulative gas and liquid productions. The differences in productions among well trajectories exceed 30% under different well configurations.
With the augmented growth of production from unconventional reservoirs, horizontal well technology has grown in oil and gas industry, yet study of well geometry in production system remains to be limited. This study is a unique effort to optimize well configuration and perforation placement in order to alleviate multiphase flow problems in the wellbore. Providing the practical potential on simulation works, this study provides a predictive guidline to connect well geometry selection and production optimization.
The separation of gas from gas-liquid mixture in horizontal wells has become a growing concern in the oil and gas industry. The produced free gas reduces the efficiency of rod pump systems, minimizes oil production and can lead to the failure of the rod pump system due to gas locking phenomena. The impact of two-phase flow on the new horizontal well gas anchor’s performance was investigated experimentally. Each experiment was conducted in a transparent horizontal well flow loop by using water and air as the test fluids. Experiments with and without the new gas anchor in the flow loop cases were studied. The new tool has two mechanisms to prevent gas phase from entering the tubing. The first mechanism is the breakage of the mixture’s wave by the bull plug of the tool. The second mechanism is the separation of small gas bubbles due to the flow through the tortuous path inside the tool. This experimental program quantifies the tool performance regarding the first working mechanism only. The bubble separation via the tortuous path mechanism was not investigated.
The results showed that both with and without tool cases can separate 90 – 100% gas from the mixture, if the inlet of tubing or the tool was fully submerged under liquid phase of the mixture at all time. This condition was achieved under stratified flow where the horizontal part of the well was toe flat or toe-up (0°, +1°, and +2°). The wave breakage mechanism by the bull plug of the tool was confirmed visually. This breakage mechanism established the advantage of using the new gas anchor over no-tool condition.
An operator in west Texas experienced an obstruction pumping down a plug and perforating gun combination on a multi-stage frac operation in a 23,600-ft lateral. Following a 3.74" OD gauge run with 2-3/8" coiled tubing (CT), which hung up at 18,266 ft, a 3" gauge run was able to pass the holdup depth (HUD). To determine the cause of the restriction, the operator decided to run a video camera and a multi-finger caliper tool. However, due to some concerns with CT reach in the long lateral, issues with friction reducers, undesirable memory timers for recording the logs, and the inability to repeat logging in zones of interest or missing data, the camera provider recommended the logging be performed in "real time" on an electric-line (e-line) tractor.
A shop systems integration test of the combined tractor, caliper and camera was performed prior to running in the well. Clear fluid (fresh water) was pumped down the 5.5" × 4.5" casing from surface to obtain quality video downhole. Upon running the live system with the tractor, several over-torqued collars were identified as well as some buckling above those collars. The images were clear, and the problem areas were successfully identified. The total distance tractored was 10,063 ft, passing through the bad collars to the total measured depth of 23,511 ft.
This was the first time that a downhole video camera was run in combination with a multi-finger caliper tool on an e-line tractor in one run. This service benefits the industry in the following ways: Flexible logging program with real time diagnostics and decisions on additional passes in problem areas. No fluid darkening friction reducers necessary to achieve long lateral total depth. No CT helical buckling concerns. Small foot print for logging program on multi-well pads. Less chance of damaging logging tools on tractor than on CT if obstructions encountered.
Flexible logging program with real time diagnostics and decisions on additional passes in problem areas.
No fluid darkening friction reducers necessary to achieve long lateral total depth.
No CT helical buckling concerns.
Small foot print for logging program on multi-well pads.
Less chance of damaging logging tools on tractor than on CT if obstructions encountered.
This paper describes the operational details of this case and offers insights into the potential uses for such a service to the industry.
Coiled Tubing (CT) is widely used in wellbore cleanout operations to remove solid particles such as drilled solids or residual proppant from the hydraulic fracturing treatments. The cleanout operation is often associated with inefficiency and substantially increases the operational cost. This study is aimed at developing a model to predict the required fluid circulation rate and time to efficiently remove solids from the wellbore and optimize cleanout operation.
To study the hole cleaning mechanism, solids bed erosion experiments were conducted using a flow loop that has a 10.4 m long annular (127 mm × 60 mm) test section. The effects of solid density, flow rate, inclination angle and fluid type on cleanout operation were investigated by measuring bed erosion and hole cleaning efficiency. A stable bed was initially formed in the annular test section of the flow loop. Once the setup was positioned at the desired inclination, the bed was eroded for 30 minutes at a constant flow rate. The amount of solids removed during each test was weighed to determine cleanout efficiency. A traveling camera system was utilized to measured bed height at different locations in the test section. The measurements resulted in the generation of bed erosion curve (average bed height versus circulation time plot) for each test. The trends are consistent with previously reported measurements; however, certain discrepancies were found when examining the trends.
This study indicates that solid density has a slight to moderate effect on hole cleanout operation. For a given flow rate, high-density solids make hole cleaning much more challenging, especially in near horizontal well sections. The critical angle of inclination that is defined as the angle at which cleaning is the most difficult was not significantly affected by the density of the solids. Irrespective of the density of solids, the effective cleanout fluid to be used in wellbore cleaning operation at all inclinations remained the same.
The outcomes of this investigation can be applied in the field to optimize cleanout operations in horizontal and deviated wells. The bed characteristics recorded during the investigation give more insight into the mechanisms of solids transport in inclined wellbores and can be used as the basis for further investigation.
Liu, Yongsheng (China University of Petroleum, Beijing) | Gao, Deli (China University of Petroleum, Beijing) | Li, Xin (China University of Petroleum, Beijing) | Qin, Xing (China University of Petroleum, Beijing) | Li, He (China University of Petroleum, Beijing) | Liu, Hang (Yibin Natural Gas Development Company Limited)
Jet comminuting technology has proved to be an effective means of solid particle pulverization, and current research attempts to introduce it for drilling work to reduce cuttings size, because smaller cuttings are easy to circulate out of the bottom, thus can effectively prevent the formation of cuttings bed, especially in horizontal drilling. In this paper, the feasibility of cuttings’ comminution by jet is studied by means of numerical simulation with secondary development. The coupling analysis methods—including the computational-fluid-dynamics/discrete-element-model (CFD/DEM) modeling for the interaction between fluid and cuttings and the particle replacement and bonding modeling for cuttings breakage—are used to characterize the jet comminuting process of cuttings. Input parameters of simulation are reliable and verified by uniaxial compression tests. Case studies presented here indicate that cuttings can be considerably accelerated by 20 to 30 m/s through the throat, which provides a good effective speed for the cuttings. After being accelerated by the fluid and crushed with the target, the vast majority of cuttings results in smaller debris. Also, increasing the inlet speed affects the crushing efficiency. The inclination of the target at near 65 shows good results. This paper proposes a new perspective to introduce the jet comminuting technique for drilling operations, and its findings could help in guiding engineering design in the future.
ur Rehman, Syed Raza (Qatar University) | Zahid, Alap Ali (Qatar University) | Hasan, Anwarul (Qatar University) | Hassan, Ibrahim (Texas A&M University at Qatar) | Rahman, Mohammad A. (Texas A&M University at Qatar) | Rushd, Sayeed (King Faisal University)
Horizontal drilling technology has shown to improve the production and cost-effectiveness of the well by generating multiple extraction points from a single vertical well. The efficiency of hole cleaning is reduced because of the solid-cuttings accumulation in the annulus in cases of extended-reach drilling. It is difficult to study the complex flow behavior in a drilling annulus using the existing visualization techniques. In this study, experiments were carried out in the multiphase flow-loop system consisting of a simulated drilling annulus using electrical resistance tomography (ERT) and a high-speed camera. Real-time tomographic images (quantitative visualization) of multiphase flow from ERT were compared to the actual photographs of the flow conditions in a drilling annulus. The quantitative analysis demonstrates that ERT has a wide potential application in studying the hole-cleaning issues in the drilling industry.
Along-hole depth is the most fundamental measurement in our business of making and using subsurface measurements, tying together all downhole data services provided. Driller’s way-point depth (DwpD) correction is applied to calibrated drillstring length and, together with an associated uncertainty, provides true along-hole (TAH) depth. An earlier paper outlined DwpD theory. This paper reviews the methodology and describes the results of applying DwpD corrections in a field trial.
Logging-while-drilling (LWD) measurements are typically recorded using uncorrected driller’s depths while drilling down. When the drillstring is pulled out of hole (POOH) in a simple sliding state, DwpD correction of drillpipe depth can be applied in a way similar to the way-point correction used to correct wireline depth. The parameters necessary to calculate the correction include downhole temperature measured at the bottomhole assembly (BHA) and pipe axial tension measured as surface hookload (SHL). Both of these are measured as the drillstring is withdrawn from the well. These are the inputs to the DwpD thermal- and elastic-stretch corrections and these are applied to the calibrated length of the individual pipes that make up the drillstring.
DwpD corrections were applied in a field trial where two deep deviated off shore appraisal and development wells with along-hole depths of around 14,000 ft (Well 1) and 15,000 ft, (Well 2) that were drilled using composite 5- and 5.875-in. tapered drillstrings. Because the entire drillstring was under tension while being pulled out of hole, the corrections applied, amounting to around 100 ft at total depth (TD), are larger than those that might be expected using conventional methods. The field test results show that DwpD corrected depth is comparable to WLL logged depth.
The results show sensitivity of the corrected along-hole depth measurement to the tension profile, the temperature profile, the wellbore geometry and the drillstring architecture. The results highlight the differences between the originally logged LWD depth, the WLL logged depth and the DwpD corrected depth. The associated uncertainty of the DwpD corrected TAH depth then provides a context within which these differences can be resolved.
Al Saedi, Ahmed Q. (Missouri University of Science and Technology ) | Flori, Ralph E. (Missouri University of Science and Technology ) | Kabir, C. Shah (Missouri University of Science and Technology and University of Houston)
Temperature-profile distributions in a wellbore during drilling operations might take different forms when applying the energy balance in the overall system. For steady-state conditions, wherein the wellbore is considered a closed system, adding any source of additional energy to this system can influence the predicted temperature profiles. This study presents a new analytical model to investigate the influence of rotational energy arising from the drillstring operation on the wellbore-temperature behavior.
A significant part of the drilling operation is rotation of the drillstring. Depending on the drilling rig, various equipment provides this kind of energy, such as the rotary table or topdrive. In addition, downhole motors or turbines can add additional rotation to the drill bit. This type of energy source can be construed as a supplemental heat source that could be added to the formulations of drillpipe- and annular-temperature profiles.
Overall, this study presents two models involving frictional and rotational energy. These models yield the same solution if we do not include the energy source, and they can apply equally well for any energy-balance system. The proposed mathematical models provide new insights into different energy terms that can be included to compute the temperature profiles in the drillpipe and annulus.
Patron, Katherine Escobar (Schlumberger) | Chen Billdal, Xin (Schlumberger) | Lu, Haidan (Schlumberger) | Kutluev, Denis (Schlumberger) | Kimery, Dave (Heal Systems) | Gau, Kyla (Heal Systems) | Diederichs, Lauren (Heal Systems) | Fears, Soraya (Heal Systems)
The artificial lift strategy of an asset is driven by technical and economic factors. Production challenges associated with the exploitation of unconventional plays have become a key factor when planning for a life time solution. Inherent flow instabilities associated with the production of unconventional shale wells should be taken into consideration during the production and optimization of the well. Transient simulation is adopted to gain insights into dynamic flow mechanisms and consequently design for a customized tail pipe system for the life of the well.
This paper describes a case study where a Horizontal Enhanced Artificial Lift (HEAL) System is implemented together with a rod pump as the artificial lift strategy for an unconventional shale asset in the US. Dynamic transient simulation was conducted to demonstrate the efficiency of the system in significantly suppressing slug flow by conditioning flow through a regulating string and separating gas from the well stream before it reaches the installed artificial lift system. Comprehensive engineering scenarios are set up to analyze the effect of production parameters on the HEAL System design against conventional production approaches, where equipment run life is compromised due to unstable flow conditions and consequently the amount of gas and/or solids that are produced through the pump.
The combination of transient simulation with artificial lift demonstrates that the HEAL System is a suitable solution for the production challenges associated with unconventional reservoirs. Extending the life of the equipment allows the well to produce at a lower bottomhole pressure and manage slug flow. The solution can be extended to unconventional places where unstable production due to reservoir pressure depletion is a dominant factor.