In days where the oil price is low, cost optimization is of vital importance. Especially in mature oil fields, the reduction of lifting costs by increasing the mean time between failure and the overall efficiency helps to stay economical and increase the final recovery factor. Today a significant portion of artificially lifted wells use sucker rod pumping systems. Although its efficiency is in the upper range, compared to other artificial lift systems, there is room for improvement and system optimization.
This paper presents the benefits of the field-tested Sucker Rod Anti-Buckling System (SRABS), which can entirely prevent compressive loads from the sucker rod string by a redesign of the standing valve, the advantageous use of the dynamic liquid level, and the on a case-by-case basis application of a tension mass. This results in complete buckling prevention and a reduction of the overall stress in the sucker rod string.
The resulting reduction in the number of well interventions in combination with the higher overall pumping efficiency prolongs economic production in mature oil fields, even in times of low oil prices. The analysis of SRABS, using simulations, showed a significant increase in the overall efficiency. The SRABS performance and wear tests under large-scale conditions are performed at the Montanuniversitaet Leoben's Pump Testing Facility and in the field. The self-developed Pump Testing Facility can simulate the conditions of a 500 m deep well, including the effects of dynamic liquid pressure and temperature. Testing of SRABS has identified major benefits in comparison to standard sucker rod pumps.
The results of intensive testing are used to optimize the geometry of the pump body itself and to improve the wear resistance by selecting optimal materials for the individual pump components. SRABS itself can be applied within every sucker rod pumping system; the installation is as convenient as for a standard pump, and manufacturing costs are comparable with those of a standard pump. This paper shows the high performance of the SRABS pumping system in comparison to a standard sucker rod pump.
Varshney, Mayank (Cairn Oil and Gas, Vedanta Limited) | Goyal, Aman (Cairn Oil and Gas, Vedanta Limited) | Goyal, Ishank (Cairn Oil and Gas, Vedanta Limited) | Jain, Akanksha (Cairn Oil and Gas, Vedanta Limited) | Pandey, Nimish (Cairn Oil and Gas, Vedanta Limited) | Parasher, Arunabh (Cairn Oil and Gas, Vedanta Limited) | Vermani, Sanjeev (Cairn Oil and Gas, Vedanta Limited) | Negi, Anil Singh (Baker Hughes, A GE Company) | Sharma, Vinit (Baker Hughes, A GE Company)
Waterflood is most commonly used secondary recovery mechanism in conventional sanstone reservoirs worldwide. Waterflooding assists in pressure maintenance and increases the field estimated ultimate recovery (EUR). Conformance in water injector wells plays an important role during waterflooding of a reservoir. Better conformance results in improved vertical sweep efficiency leading to higher recovery.
Continuous injection of fluids into the reservoir at higher rates may create channels for preferential flow. Zones of higher permeability, leading to higher injectivity in selective zones, can also exist because of various lithological conditions and rock structures comprising of naturally occurring fractures or fissures. For injection wells, the entry of fluids into a set of perforations is governed by the quality of the perforations and the permeability of the formation at that depth. Preferential flow of injected fluids into selective pay intervals results in diminished overall sweep efficiency. (J. Vasquez, et.al., 2008).
This paper discusses the use of thermally activated gels from polyacrylamides and metal chelates applied for selective reservoir matrix permeability reduction in an injector well. A low concentration, low viscosity delayed crosslinker gel system employing partially hydrolyzed polyacrylamide (PHPA) exhibiting 12-14% degree of hydrolysis level with chromium acetate as crosslinker offering delayed gelation time was used to selectively isolate one of the payzones.
A non-profile retrievable (NPR) plug was installed to isolate the target interval from the rest of the pay zones to enable selective treatment of the interval using coiled tubing (CT). The fluid was customized to minimize CT friction while ensuring that the rheological properties of the fluid in the reservoir would achieve the desired diversion and allow delayed gel crosslinking mechanism assuring avoiding of gel crosslinking in CT while pumping in progress. Denser brine relative to the delayed gel density was spotted above the NPR plug to avoid gel settling on the plug for easy retrieval of the plug post-treatment. Injectivity was measured and subsequently, the treatment was placed as per design while constantly monitoring the pressures so as to qualitatively determine the effectiveness of the treatment placement.
The treatment resulted in significant alteration in injectivity of the targeted zone. Post-treatment production logs confirmed an improvement in the injection conformance. Later, the zone was isolated and the bottommost zones were selectively stimulated enhancing the injection and thus improving sweep efficiency. Since the crosslinked gel system is not prone to any disintegration when in contact with acidic interventions, the treatment ensures a superior longevity of the conformance control when compared to other conventional diversion or zonal shut-off treatments.
The success of the treatment substantiates that the CT deployed low viscosity, low concentration delayed crosslinked gel system application can be successfully extended to selective water shut-off applications in producer wells. The injector profile modification treatment executed offered a comprehensive solution to conformance issues enhancing volumetric sweep efficiency, pressure maintenance across depleted sands and avoiding further water cycling in producer wells.
A full-field dynamic simulation model has traditionally been seen as the benchmark for assimilating all available static and dynamic data to develop robust production forecasts. Santos’ experience modelling the Walloon Coal Measures in its Surat Basin acreage has shown that the performance of individual wells producing from this CSG reservoir is governed by reservoir variability at a fine-scale. This presents a fundamental challenge in developing full-field dynamic models that can accurately describe and predict production performance down to the scale of individual coal seams.
Current Queensland CSG projects have focussed on the most prospective acreage, however as subsequent developments move to more marginal areas a greater understanding of the subsurface will be required for optimum development. The target formations will increase in geological complexity, such as Santos’ Surat Basin acreage on the edge of the CSG fairway. Here wells produce from a greater number of distinct coal reservoir units, and how these reservoir units are structured and relate to each other governs reservoir connectivity and defines long-term production performance. Each reservoir unit is comprised of multiple coal plies, all with their own unique maceral distribution and cleating characteristics. These fine-scale properties define the reservoir's dynamic behaviour, and can be impossible to upscale such that these characteristics are preserved at a coarse scale. Consequently, accurately modelling individual well performance will require a fine-scale model to capture and characterise this variability.
In development areas where the quantity and quality of reservoir data gathered from exploration and appraisal is sparsely populated, these fine-scale models will need to be populated geostatistically. Without model-scale appropriate control data from production and pressure measurement in the development wells to provide constraints however, a probabilistic model will not accurately define fine-scale behaviour of specific reservoir units. These data requirements can help shape the appraisal scope for new areas and define an appropriate level of surveillance for producing assets.
Traditional full-field dynamic modelling has fundamental limitations for interrogating complex unconventional CSG reservoirs at a fine scale. Because of this, alternative workflows are required to answer the subsurface questions necessary to develop CSG assets such as the Surat Basin effectively. This paper details a selection of workflows explored to address this pragmatically, as well as their limitations and associated data requirements. This will also assist in identifying data gaps needed for optimum reservoir management and to aid in the development of these challenging CSG reservoirs.
Ismail, Syahezat (PETRONAS Carigali Sdn Bhd) | Sy Rahim, Sy Puteh Mariah (PETRONAS Carigali Sdn Bhd) | Yahia, Zaidil (PETRONAS Carigali Sdn Bhd) | Elshourbagi, Saied Mustafa (PETRONAS Carigali Sdn Bhd) | Ishak, M Faizatulizuddin (PETRONAS Carigali Sdn Bhd) | Roslan, M Rizwan (PETRONAS Carigali Sdn Bhd) | Che Hamat, W Afiq Farhan (PETRONAS Carigali Sdn Bhd) | Ben Amara, Abdel (Silverwell Energy) | Faux, Stephen (Silverwell Energy) | Makin, Graham (Silverwell Energy)
Moving to digitalization era in the current low oil price environment, paradigm shift is really crucial in managing brownfield development and production. The challenge is to select the best technology to harvest the optimum production from the field but at the same time reduce potential capital and operating expenditure.
The paper highlights the technology evaluation of Digital Intelligent Artificial Lift (DIAL) system. This includes it's working principles, candidates screening, risk mitigation plan as well as technology success criteria developed specifically for the technology.
DIAL system is an in-well gas lift system that can overcome the well design and operational limitations of existing side pocket mandrels and valves. DIAL enables a better gas lift well design as well as able to interconnect downhole and surface monitoring & control in real-time. It provides opportunity for automation, better subsurface and surface integration as well as minimizing well intervention requirement.
Based on the promising technology evaluation, one pilot well was identified by the team at DL field. The well was part of DL drilling campaign executed in Q2 2018. Details of the well design & scope, as well as gas lift design for the well will be shared. Commercial comparison was demonstrated between conventional side pocket mandrel system and the DIAL system.
The case study at DL field will be discussed in details, starts from their wells’ design, technology deployment strategy, installation, production test result as well as lessons learnt during installation and operationalization of the system.
Moving forward from the pilot application, root cause failure analysis was done, lessons learnt were identified, design improvements were proposed and continuous monitoring of the system will be done, according to the success criteria outlined. Potential replication candidates have also been identified by the team with at least 10 promising potential candidates to be installed within the next 2 years.
The technology deployment was the result of collaborative works between PETRONAS, Silverwell Energy and Neural Oilfield Service.
Coal seam gas (CSG) well operators typically follow an industry rule of thumb 0.5 ft/s liquid velocity to prevent the onset of gas carryover during CSG dewatering operations. However, there is very little experimental data to validate this rule of thumb with only a publication by Sutton, Christiansen, Skinner and Wilson [
The University of Queensland Well Simulation Flow Facilities were designed to replicate as closely as possible the production zone of a typical vertical CSG well in Queensland, Australia in transparent acrylic pipes to observe two-phase flow behavior in simulated downhole conditions. The annular test section in the rig was constructed of a 7-in casing and 2¾-in tubing. Modification of the experimental setup to include a vertical separator allowed for the detection of gas carryover. Conceptual demonstrations of gas carryover were captured and have been illustrated. The experiments in this study validate the industry rule of thumb of 0.5 ft/s liquid velocity as an appropriate guideline for onset of gas carryover in a casing-tubing annulus dimension similar to a typical CSG well in Queensland.
Wei, Bing (Southwest Petroleum University) | Zhang, Xiang (Southwest Petroleum University) | Lu, Laiming (Southwest Petroleum University) | Xu, Xingguang (The Commonwealth Scientific and Industrial Research Organization) | Yang, Yang (The Commonwealth Scientific and Industrial Research Organization) | Chen, Bin (CNOOC Enertech-Drilling & Production Co.)
Although the low salinity effect (LSE) in enhanced oil recovery (EOR) is widely accepted, its underlying mechanisms have not conclusively determined largely due to the complex interactions at oil/brine/rock interfaces and their relation with the dynamic flow behaviors in porous media. Given the vast diversity of brine composition in different reservoirs, the current studies are not yet sufficient to map the complicate interfacial behaviors. Therefore, the attention of this work was placed on the events that occurred on oil/brine/rock interfaces through direct measurements of oil water IFTs, interfacial dilational rheology, zeta potential and oil water relative permeability in sandstone porous media. The effect of brine composition including ion types, salinity and valency on LSWF was examined for the intent of re-defining the potential-determining-ions (PDIs) for LSE. The results showed that the oil water interfacial behaviors closely depended on the brine composition. The wettability alteration of the sandstone surface was found to be associated with the divalent ions and the double layer expansion (DLE) failed to interpreted the observed wettability in our work. The injection of MgSO4 brine produced the highest oil recovery factor compared to other three brine. On the basis of the previous observations, we concluded that the LSE was strongly dependent on the events occurred on the oil-brine-solid interfaces. The most significant LSE was observed at a salinity of 2000ppm in our work and the ions of Mg2+ and SO42− appeared to be critical for LSWF.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Hilgedick, Steven A. (Missouri University of Science and Technology) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids) | Alsaba, Mortadha T. (Australian College of Kuwait)
It is recognized that there is no single solution to lost circulation, and most treatment and trial-and-error. However, the screening guide presents a high-level ‘go to’ document with coherent guidelines, which engineers can utilize in making decisions regarding lost circulation treatments in major oil fields. The aim of this work is to describe how mud engineers can use the decision tree analysis (DTA) to evaluate and select the best treatments path for mitigating mud losses.
Lost circulation events of Southern Iraq oil fields were statistically analyzed to determine treatment effectiveness. Also, the cost of each treatment, as well as the NPT that is associated with the treatment, is considered in this study. Data from over 1000 wells were gathered from various sources and reports; the
treatments were classified by scenario -partial, severe, and complete losses - as well as cost, efficiency, and formation types. This paper is developed based on probabilities, expected monetary value (EMV), and decision tree analysis (DTA) to recommend the best-lost circulation treatments path for each type of losses.
Traditionally, lost circulation in Southern Iraq area has been treated in a multitude of ways without consistent methodology. This analysis identifies and ranks the most effective treatments to create a "best" method/product recommendation and a flowchart suggesting additional measures in treating losses to optimize success and reduce overall cost and NPT. This paper presents the best treatment for each scenario - partial loss, severe losses and complete losses - both for product selection and engineering.
This paper utilizes probability and economics in the decision-making process. This is the first study that considers a detailed probability and cost to treat the lost circulation problem. Thousands of treatment scenarios for each type of losses are conducted, and the EMVs for all scenarios are calculated. For each type of losses, the lowest EMV treatment strategy- that is practically applicable in the field and makes sense- is selected to be used to treat each type of losses to minimize NPT and cost. If the losses didn't stop after utilizing the proposed treatment strategies, it is recommended to use liner hanger to isolate the losses zone and then continue drilling.
One challenge in drilling wells in Southern Iraq oil fields is the inconsistency of approaches to the lost circulation problem. Therefore, the result of this data analysis provides a path forward for Southern Iraq area lost circulation events and suggests probable methods that can be used in similar formations globally. Additionally, the methodology can be adapted to studying other types of formations and drilling challenges have the same geological properties in any major oil field.
Shi, Xian (China University of Petroleum) | Li, Dongjie (China University of Petroleum) | Cheng, Yuanfang (China University of Petroleum) | Han, Zhongying (China University of Petroleum) | Fu, Weiqi (China University of Petroleum)
Fixed plane perforation technology is regarded as a good mean to address near wellbore tortuosity and reduce breakdown pressure in low permeability reservoirs. To better understand of the fracture behavior in wellbore perforations at the defining plane, a 2D finite element model has been implemented in ABAQUS to investigate the effects of mechanical, perforation and treatment parameters on hydraulic fracture propagation path. The global zero thickness cohesive elements have been inserted into numerical model, thus the existence of natural fractures on patterns of fracture propagation can be considered in this model. It shows that there is a great impact of natural fracture on the fracture propagation path. Moreover, the fracturing fluid viscosity, pumping rate, in-situ stress and perforation parameters also play critical roles on fracture propagation. Comparisons of numerical simulations show that the effects of the stress anisotropy, pumping rate, fluid viscosity, Young's modulus, Poisson's ratio and perforation intersection angle on the hydraulic fracture geometry of exterior fractures and interior fracture at the defining plane are different. It found that the width of interior fracture is almost zero at the near wellbore zone at the end of pumping which induced by the stress interference of neighboring fractures in some cases, thus perforations design at the defining plane must be carefully considered. Additionally, in most cases, hydraulic fractures from exterior perforations tend to propagate upward and downward simultaneously. Although hydraulic fractures initiated from a perforation that misaligned with the direction along the maximum in-situ stress initially at short distance, hydraulic fractures would finally reorient itself to the maximum in-situ stress direction, thus increase chances of creating one simple transverse fracture along maximum in-situ stress orientation. Because the strong stress interference of competing fractures, the possible breakdown of casing and perforation tunnels should be considered before well completion. The simulation results from this study offer some insights to enhance fixed plane perforation design for hydraulic fracturing treatments.
Tran, Tung V. (Biendong POC) | Truong, Tu A. (Biendong POC) | Ngo, Anh T. (Biendong POC) | Hoang, Son K. (Biendong POC) | Trinh, Vinh X. (Biendong POC) | Dang, Tuan A. (Biendong POC) | Ngo, Hai H. (Biendong POC)
Despite the importance of determining the maximum recovery and optimum production strategy for gas-condensate reservoirs under aquifer support, a rigorous systematic methodology is not available in the literature. Instead, most existing studies relied on running reservoir simulations with fine grids or LGR constrained by simulation runtime, producing great uncertainty in the reliability of the results. In this study, a comprehensive and systematic study of gas-condensate reservoirs under aquifer support was conducted instead.
This study focused on first benchmarking radial simulation models to available analytical solutions to within 1% of pore pressure prediction. Next, Cartesian grids were benchmarked against the calibrated radial model before applying to full field reservoir model. The full field reservoir model was then history-matched for all wells before various production regimes were simulated to determine optimum production strategy. Sensitivity analysis of water-breakthrough and total produced water volume were investigated under various aquifer sizes, formation reservoir properties, and production regimes. Optimum production strategy was selected to maximize the hydrocarbon recovery while reducing the water treatment costs.
The approach focused on the construction of benchmarked models to describe the water breakthrough phenomena and to investigate the impact of aquifer on deliverability and ultimate recovery of a gas-condensate reservoir. Factors that could affect recovery such as withdrawal rate, aquifer size, formation permeability, and vertical-to-horizontal permeability were examined. Different production schemes were then simulated on a history-matched full field model to determine optimum strategy.
It was found that for better reservoir quality (permeability greater than 100 mD), withdrawal rates do not have significant impact on ultimate gas recovery. On the other hand, with increasing withdrawal rate cumulative condensate recovery decreases and total water production increases. Aquifer size has large impacts on recovery factor, water breakthrough time, and total water production. For medium and strong aquifers, it was found that the field water handling capacity could impose a significant constraint on ultimate recovery and upgrading water handling capacity later in the field life may be instrumental in improving recovery.
The Australia Pacific LNG (APLNG) Downstream Project comprised construction of a two-train LNG plant, two 160,000 m3 LNG storage tanks, a LNG loading jetty, and associated infrastructure on Curtis Island, near Gladstone, Queensland. The facility utilises ConocoPhillips’ proprietary Optimized Cascade ® process to liquefy natural gas. Project planning began in 2008 and construction commenced in 2011. LNG production from Train 1 began in December 2015 and Train 2 came on line in October 2016. In August 2017, the final 90-day two-train lenders test was successfully concluded and included an operational component in which the LNG Facility operated at ten per cent above nameplate capacity for the 90-day period. This successful outcome was achieved through collaboration, integration and robust execution plans by the APLNG Operations, APLNG Project, ConocoPhillips LNG Technology and Licensing and Commissioning and Start-up work teams. In an effective strategy to support the drive to APLNG first cargo, the combined teams formed a fully Integrated Completions Team in 2015. This team worked together enabling rapid development of the operations workforce capability and resulted in both trains achieving performance tests at first attempt.
The APLNG Project operability assurance and operations readiness program commenced with a collaborative workshop, attended by Operations, Projects and Commissioning and Start-up representatives. A focus on high collaboration and integration between the teams backed by ConocoPhillips’ Operability Assurance (OA) and Operations Readiness (OR) principles identified 370 critical business deliverables. Learnings were leveraged from across ConocoPhillips assets (including Darwin LNG) as they pertained to readiness best practice. APLNG Readiness Assurance guidance was established to create specific functional readiness trackers to measure every action supporting the 370 deliverables. A simple and effective tool was developed and supported by robust monthly review forums where each action was tracked and rolled up to S-Curves. These deliverables translated to over 7,000 unique line items tracked over the entirety of the readiness implementation. This work was leveraged by the Integrated Completions Team which implemented robust lessons learned from Train 1 to realize immediate results, delivering a 33% reduction in the Train 2 start-up schedule.
The combined efforts of the teams delivered two highly operational trains within the 2016 calendar year resulting in the production of additional cargoes. The successful execution and implementation of OA/OR principles combined with strong integration of APLNG Operations into the APLNG Project phase laid the foundation for exceptional first year operational and production performance. This meant the APLNG Operations Team moved from a newly formed team to a high functioning and critically evolving team in support of the APLNG Downstream LNG Facility.