Hussein, Ahmed (Exprogroup) | Alqassab, Mohammed (Exprogroup) | Atef, Hazem (Exprogroup) | Sirdhar, Siddesh (Exprogroup) | Alajmi, Salem Abdullah (KOC) | Aldeyain, Khaled Waleed (KOC) | Hassan, Mohamed Farouk (KOC) | Goel, Harrish Kumar (KOC)
Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Wells are tested periodically using multiple conventional test separators and data is subsequently used to update Well Performance "Nodal analysis" and "Live Flow Line Surface Network Model".
A different approach was tested in 2018 for a mature oil field in the Middle East to evaluate the effectiveness of Clamp-On based SONAR Flow Surveillance solution against existing conventional portable test separator. The objective was to check the performance of the SONAR Flow Surveillance on black oil wells at different flowing conditions, and ultimately implement a new approach to increase the testing frequency, reduce any potential of hydrocarbon release, avoid well shutdown, optimize operating costs, and production optimization.
The SONAR Surveillance approach is based on SONAR clamp-on flow meters deployed in conjunction with compositional (PVT) and multiphase flow models for oil and gas wells to interpret the measurements of the SONAR flow meters at line conditions (pressure, temperature, fluid stream composition), and output the gas, oil and water phase flow rates at both actual and standard conditions. The SONAR meter measures the bulk flow velocity (at line conditions), then a flow computer determines the individual phase volume fractions at actual conditions using a PVT model and water-cut. This provides a measure of the oil rate at actual conditions. A shrinkage factor calculated by the black oil model is applied to report oil rate at standard conditions. Gas and water are also inferred in a similar manner. The gas, oil and water flow rates thus determined at actual conditions are further processed and converted to standard conditions as well.
The field tests showed that the SONAR Flow Surveillance approach allowed more flexibility in terms of field installation and the measurements are made at actual production conditions unlike other devices that may introduce additional flow restrictions. The SONAR meters diagnostics also provided a more realistic representation of the well flow profile since the measurements are instantaneous versus the "averaging" effects observed when using gravity-based separators. This allows better production surveillance and understanding of changes in well behavior.
Current industry trend of "manufacturing" approach to develop unconventional shale reservoirs would make the journey to reach an optimized solution long by considering the historical deployment of current and emerging technologies in the last decade in North America. The basic premise is that "
The Current work is based on the utilization of Kinetix-Intersect; modeling results were compared to Stimplan for a selected stage and rate transient analytical results. Highly complex heterogeneous hydraulic fractures are created during the first dynamic process resulting in variable areal and vertical pressure distribution and flow anisotropy occurred during the second dynamic process or production phase. Kinetix-Intersect model results indicated a variable recovery factor distribution after 30 years of production, 8.9% in the near-wellbore dynamic nano-darcy region, 2% and 1.7 % for the inter-hydraulic fracture and external feeder regions respectively for the shale oil producer evaluated. Kinetix-Intersect model results indicated that about 2/3 of total hydrocarbons produced are contributed by the near-wellbore dynamic nano-darcy and inter-hydraulic fracture regions and the remaining 1/3 by the external feeder region. Acknowledging the variability of recovery factor distribution and pressure depletion associated to the producer drainage area should be the basis for the potential implementation of Enhanced Oil Recovery (EOR) techniques.
For the shale oil producer analyzed in this study, current model results indicate an asymmetrical shape drainage area and a variable well spacing in the range of 350 to 400 meters based on displacement efficiency and non-uniform recovery factor distribution. From a pressure depletion perspective, the estimated well spacing should be at least 400 meters. However, an optimum full field development would require the consideration to implement variable well spacing and tailoring completion and fracture treatment designs based on timely identification of areal and vertical heterogeneity of static/dynamic reservoir and geomechanical drivers to optimize project economics. Streamlines were used as a drainage qualitative indicator tool to help defining well spacing criteria. In summary, the route to attain better recovery factors for unconventional shale oil reservoirs commence with the understanding and quantification of the areal and vertical pressure depletion distribution along the horizontal section of the parent wells based on both dynamic processes; this is a vital input to define a suitable well spacing and effectively deploy adaptable drilling, completion and fracture treatment designs to reduce the occurrence of detrimental ‘Frac –Hits’ and improve oil recovery for future parent-child wells. The current expected recovery factors for unconventional shale producers are suboptimal with natural depletion and the need to increase the recovery factor with the deployment of EOR technology is paramount.
The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
Seth, Puneet (The University of Texas at Austin) | Manchanda, Ripudaman (The University of Texas at Austin) | Elliott, Brendan (Devon Energy) | Zheng, Shuang (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin)
During stimulation of unconventional reservoirs, offset well pressure measurements are often used to estimate hydraulic fracture geometry. These measurements can also be used to make a quantitative estimate of the created fracture network area and the permeability of the stimulated rock volume (SRV) around the hydraulic fractures. Offset well pressure measurements recorded in the field clearly show a change in the pressure response of the monitor well when the injection rate in a nearby fracture treated well is changed. The shut-in period between two frac stages in the treatment well corresponds to a distinct pressure fall-off in the monitor well. We present a workflow where we analyze and match this pressure fall-off in an offset monitor well in response to fluid leak-off from a hydraulic fracture in the treatment well to estimate SRV permeability and the created fracture network area. The workflow and model are applied to field data from the Permian Basin.
A fully-coupled, 3-D, poroelastic reservoir-fracture simulator has been used to simulate pressure fall-off in the offset monitor well. Field data and simulation results are presented to show that during shut-in between two frac stages in the treatment well, a decrease in the injection rate causes the monitored offset well pressure to fall-off. We find that this fall-off in pressure is influenced by leak-off from the treatment well fracture. During the shut-in period, fluid leak-off from the treatment well fracture into the SRV region decreases the width of the fracture which consequently affects the stress-shadow and the poroelastic pressure fall-off in the offset monitor well. The pressure fall-off in the monitor well is, therefore, shown to be caused by 1) the fluid leak-off from the monitor well fracture and 2) stress-shadow relaxation around the monitor well fracture as fluid leaks-off from the nearby treatment well fracture into the formation.
We present a new method to estimate the permeability of the stimulated region around the created fractures. We show that, along with the permeability of the SRV region, the stress-shadow of the treatment well fracture on the monitor well fracture also has a significant impact on the pressure fall-off in the monitor well. We use a conceptual model to estimate the created fracture network area which can be used as a metric to identify the effectiveness of a frac job and provide insights into the generated fracture complexity during the frac job. In addition, the estimated SRV permeability and fracture network area are critical inputs in production forecast simulations that can guide an operator to make better economic decisions in a relatively inexpensive manner.
The combination of extended-length horizontal drilling and high volume hydraulic fracturing has led to previously unimaginable production increases, yet the recovery potential of unconventional oil and gas resources remains largely unrealized. Recovery factors for unconventional oil and gas wells are typically reported at < 20% in gas shale reservoirs and < 10% in the oil plays.
Neutrally buoyant ultra-lightweight proppants have been demonstrated to effectively provide production from fracture area that is otherwise unpropped and thus, non-contributive with conventional sand/slickwater hydraulic fracturing processes. Production simulations illustrate that treatment designs incorporating neutrally buoyant ULW proppant treatment designs tailored for contemporary unconventional well stimulations deliver cumulative production increases of 30% to over 50% compared to the typical large volume sand/slickwater treatments. Unfortunately, production simulation results may not sufficiently lessen risk uncertainties for operators planning high-cost multi-stage horizontal stimulations. Therefore, several field trial projects using the neutrally buoyant ULW proppant in extended-length horizontal unconventional wells are currently in progress to validate the production simulations.
Since the initial 4-stage fracturing stimulation incorporating neutrally buoyant ultra-lightweight proppant in 2007, deployment has occurred in fracture stimulating hundreds of oil and gas wells spanning multiple basins and reservoirs. Most of the wells are vertical or relatively short lateral wells common to asset development practices predating the unconventional shale completions mania, but many were targeted at the same unconventional reservoirs as the current multi-stage horizontal completions. Several published case histories have documented the production enhancement benefits afforded by the legacy ULW proppant wells, but questions remained as to how those lessons might be correlated to provide engineers confidence in the current production simulations.
Well completion and production information was mined from the various accessible databases for the neutrally buoyant ULW proppant wells. The scope of the legacy data compiled for analysis was limited to the reservoirs common to the current field trials and production simulations, ie. unconventional oil and gas shale reservoirs. Production performance contributions of neutrally buoyant ULW proppant in past applications were compared with the production uplift observed in applications and/or simulated application of neutrally buoyant ultra-lightweight proppant fracturing treatments in current multi-stage horizontal reservoirs.
The lessons learned from this investigation provide the practicing engineer the means to confidently assess production simulation data for multi-stage horizontal unconventional completions incorporating neutrally buoyant ulw proppant in the treatment designs.
A field-trialed ball-activated Outflow Control Device (OCD) is presented that eliminates coiled tubing intervention in SAGD injection wells when converting from steam circulation to SAGD. This paper builds on a previously presented paper by the same authors where the design and tool qualification of the ball-activated OCD was presented (
The field trial of the ball-activated OCD is compared to coiled tubing shiftable OCDs on three main criteria: job efficiency, confirmation of shift, and environmental, health, and safety (EHS) considerations. Acoustic-based monitoring equipment and pressure signatures were used to confirm successful ball-activation of the ball-activated OCD. A tension response from the coiled tubing was used to confirm shifting of the coiled tubing shiftable OCDs. Steam modelling and observed tubing pressure drop data is also shared for all trials as another indication of successful shift.
In five of six ball-activated OCD shifts, the tools functioned as intended with clear pressure and acoustic signatures confirming a successful shift of the sliding sleeve. One of six was intentionally left closed. In addition, the jobs were completed more efficiently and with less EHS risk than the coiled tubing shiftable OCDs. The coiled tubing shifting tension data indicated that two out of six coiled tubing shiftable OCDs were successfully shifted, with inconclusive shifts occurring on three OCDs, and one left intentionally closed. The observed pressure drop data presented, indicates that shifting was successful in all ball-activated trial wells, and two of three coiled tubing shiftable trial wells.
The ball-activated OCD is a novel tool for use in SAGD injector wells to improve efficiency by reducing operational time and personnel required in shifting OCDs. In addition, the shift confirmation pressure signature and optional acoustic monitoring provides greater confidence of sleeve shift.
As a common occurrence in production operations, liquid-rich horizontal gas (and gassy oil) wells in unconventional plays develop severe instabilities at different stages of their well life. In this novel work, we first quantify the three-phase gas-oil-water multiphase flow behavior leading up to the characteristic severe loading signatures in order to better understand the dynamic heel-dominant liquids loading. Then, we demonstrate how a simple analytical diameter-and-inclination-dependent critical gas velocity equation can be used to determine the onset of the severe loading instabilities in a variety of artificial lift/liquid loading mitigation strategies, namely end-of-tubing landing (EOT), tubing/casing sizing, gas lift variations and tail pipe/dip tube. Actual high frequency bottom hole pressure data along with measured surface conditions will be used to evaluate the slugging behavior and recreate using analytical multiphase flow simulator. The flow conditions will be extrapolated to the heel/near lateral section of the well and simulated for various lift strategies.
I am encouraged that we, as an industy, continue to refine and tweak our practices to solve zonal-isolation and cementing challenges in every well environment in which we work. As cementing techniques are improved, so, too, are the cement-evaluation methods and work flows. This paper demonstrates a new way to create gas-tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed. This paper discusses shale creep and other shale-deformation mechanisms and how an understanding of these can be used to activate shale that has not contacted the casing yet to form a well barrier. Well RXY is located in Cairn’s Ravva offshore field in the Krishna-Godavari Basin in India.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.