Weatherford (Norway)

Abstract As the petroleum industry navigates increasing economic pressures, operators continue to seek cost-effective production solutions that do not compromise safety or operational efficiency. One such solution is the application of jet pump technology, which offers a rigless, flexible method for well offloading and testing. This paper presents a field case from Iraq where a jet pump was successfully implemented as an alternative to traditional coiled tubing and nitrogen-based offloading, demonstrating strong performance in terms of both flow assurance and cost savings. In 2023, a newly drilled well targeting three distinct production zones in southern Iraq was evaluated for its inflow potential. Historically, wells in this region were offloaded using coiled tubing combined with nitrogen injection, a common but costly approach that involves logistical complexities and long mobilization times (Lea et al., 2008). For this operation, the engineering team selected a hydraulic jet pump system designed using Jet Evaluation and Modeling Software (JEMS), which enabled precise nozzle and throat sizing tailored to wellbore pressure, temperature, and fluid properties (Pugh, 2009). The jet pump was deployed via slickline, offering a low-risk, non-intrusive deployment method. High-pressure power fluid was injected down the annulus, while produced fluids were returned through the tubing. Production zone testing was executed by sequentially opening individual Sliding Sleeve Doors (SSDs), allowing controlled unloading and isolated flow assessment from each zone. The system achieved a peak production rate of approximately 2,200 barrels per day (BPD), well above initial design targets. In terms of cost and operational impact, the jet pump system significantly outperformed conventional nitrogen lift. The use of rigless installation and surface-based parameter tuning eliminated the need for nitrogen tankers and reduced rig time by seven days, contributing to an overall cost savings of over 500% when compared to previous nitrogen-based operations in the same field. The field team would also be able to change nozzle and throat configurations on-site, further optimizing drawdown and pump efficiency. This level of flexibility is a well-documented advantage of jet pump systems, especially in early production scenarios or wells with high water cut and unstable flow regimes (Takács, 2015; Brown, 1977). This study reinforces the economic and operational benefits of jet pumps for initial well unloading and production evaluation. Their ability to be rapidly deployed, adjusted, and retrieved without a rig gives them an edge over conventional artificial lift techniques during early well life. In replacing nitrogen offloading, jet pumps not only reduce cost but also improve control over flowback and data acquisition. The findings from this case provide a practical and scalable model for other operators seeking to transition from conventional nitrogen kick-off to jet pump-based well stimulation strategies.

Abstract Reservoir modeling has evolved into a potent tool with the recent introduction of sophisticated computing capabilities, allowing it to capture minute reservoir features much more accurately. This study focuses on one such case history, in which a mature water-flooded field had a subsurface blowout, with naturally fractured carbonates serving as the main reservoirs. Developing an optimal field development strategy required a significant challenge: matching production history to the simulation model while faithfully capturing the subsurface blowout and its aftermath on the reservoir flow dynamics. The geologically complex reservoirs have 84 faults and four distinct sublayers with different petrophysical properties. More than thirty years of production and injection data are available for these reservoirs. Almost halfway through the production period, a subsurface blowout occurred in one of the wells, which was thought to be rectified. Building the geological model and adding reservoir properties marked the start of the investigation. The simulation model was initialized, and a history match was obtained. This match showed accuracy prior to the blowout, however there were differences in the match after the blowout period. This implied that, contrary to the first hypothesis, the consequences of blowout had persisted. Due to the blowout, there was a great deal of uncertainty about the type and extent of ongoing subsurface communication. The issue now was to manage this uncertainty and establish a strong historical match for the post-blowout period without sacrificing the pre-blowout match. Layer-by-layer and whole field history matches were obtained by varying parameters like skin, fault transmissibilities, permeability modifiers, and relative permeability adjustments. Restart runs for the post-blowout phase and entire history runs were both taken into consideration. After more than 350 simulation runs, a good match was achieved for pressures and the production rates in the post blow out period, without significantly affecting the pre blowout history match in the field. Initially the issue was most significant in two of the seven wells that were in close vicinity to the blowout well. The matches for these wells were checked for each layer separately to assess the quality of the overall match. The well histories were significantly improved from the base case, yielding a high-quality match. Based on the history matched model, increased production potential was evaluated considering areas of bypassed oil. This study had a unique case where the reservoir behavior was altered by manmade intervention, while the exact behavioral change remained uncertain. Strategies for dealing with such uncertainties were devised in a complex geological setting and encouraging results were achieved, creating a model that can used with confidence for exploring field development scenarios.

Abstract The study's main objective was to conduct a heterogeneity analysis to understand the nature of the complex carbonate reservoirs by integrating geological, and petrophysical parameters to comprehend the different types of facies and their effect on reservoir characteristics. The approach utilizes borehole electrical images to measure the extent and type of the vuggy fraction, porosity dissemination, and its impact on reservoir quality. The heterogeneity analysis of reservoirs from borehole images is carried out using proprietary software that examines the resistivity spectrum to extract information on porosity, layering and other heterogeneities to quantify, characterize and provide a distribution of these relevant heterogeneities. Several iterations are needed to optimize parameters. Each iteration is validated by comparing core data, and density-neutron x-plots with a visual examination of the images to see whether all heterogeneities are identified. Single-depth histograms were generated from the derived porosity spectrum to show the distribution of primary and secondary porosity. The Upper Shuaiba Member (USH) is the main pay zone in the Daleel field in northern Oman and is subdivided into 5 layers comprising of A, B, C, D, and E of which layers D and layer E are the most productive. These layers consist of thinly bedded bioclastic packstones and wackestones. The exploration development of the Daleel field requires knowledge of the composition and collocation of these various layers in the sedimentary system. Our method consists of several steps that combine a probabilistic image analysis with petrophysical properties to derive electrical facies based on the texture, heterogeneity, resistivity spectrum, fracture identification, and petrophysical properties. These facies are translated into curves, codes and colors that represent the porosity distribution as volume fractions. Primary and secondary porosities (vuggy porosity) are common in this field. We are able to provide color coded distributions showing the more connected vugs, partially connected vugs and isolated or tight vugs. These are separated from connected fractures. This information is critical to developing a geological model to aid field development. Borehole imagers are important to determine petrophysical parameters in highly heterogeneous carbonate reservoirs. They provide information on a wide variety of pore types including vuggy, fracture and matrix. This study shows that the USH formation contains bimodal and trimodal pores resulting from vugs. All vuggy intervals are classified as connected and unconnected vugs. The results go into a geological model to provide a deeper understanding of the facies extension across the field to optimize exploration.

Abstract The pursuit of continuous improvement in overall Health, Safety and Environment (HSE) performance represents a key driver in drilling and completion activities, even more in critical well environments. To minimize risks in subsea well operations, Eni and Weatherford developed an innovative Cable-Less Casing Valve (will be referenced as "Valve" in this paper), with the primary objective of blowout risk reduction, isolating downhole environment from surface when the bottomhole assembly (BHA) is out of the well, enhancing operational efficiency through contactless technologies easier to deploy at greater depths. This technology is the result of a joint R&D project in which a pre-existing technology (i.e., a surface cable activated casing valve) has been upgraded by introducing a contactless activation, thus unlocking the application in subsea wells, the main candidates for this technology. Once the technological needs have been identified, the Valve has been engineered, built and pilot tested in land environment in 2018 - 2019, prior to its commercial deployment occurred in the Eastern Mediterranean Sea area for three subsea wells between 2022 and 2024, achieving the expected objectives with no major interference or disruption added to the normal operations. The Valve has been developed in sizes for 13 3/8″ – 13 5/8″ and for 9 5/8″ – 9 7/8″ casings.

Abstract Prediction of pore pressures and fracture pressures is likely to deviate to ensure drilling and completing wells safely and economically. When a well is drilled with no operational drilling window to complete drilling to the target depth (TD), frequency of well control events such as gas kicks and lost circulation rises. Despite utilization of only wellbore strengthening material (WSM) alone, these issues could not be resolved. The managed pressure wells (MPW) techniques, the advanced drilling solution is the ultimate strategy when designing a drilling program to achieve the desired outcome in these types of certain formations. During the spotting and squeezing process, MPW techniques were employed to ensure the effectiveness of injecting the WSM material into the loss zone by actively managing the wellbore pressure. Issues were encountered during drilling 8-1/2" hole section, client expected the peak pore pressure of 1.936SG higher than at 9-5/8" casing shoe of 1.88SG (Well X) and 1.93SG (Well Y). Client approached first with pumping WSM to enhance the integrity of wellbores, deployed after drilling 9-5/8" shoe track to increase the fracture initiation pressure, to meet expectations as of 2.0SG. MPW techniques deployed with preliminary hydraulic modeling performed: (1) reducing the mud weight, (2) increasing the flow rate while maintaining an acceptable loss rate, and (3) applying surface back pressure (SBP), to help client achieve significant results, applied during mud displacement, tripping, running liner, and managed pressure cementing. Well X was drilled with MW 1.74SG with equivalent circulating density (ECD) controlled at 1.93SG, minimizing loss rate down until 1 to 2m3/hr. To reduce loss rate due to high ECD, WSM were used, allowing increasing to 1.78SG MW. This adjustment helped reduce drilling gas and prevent well control events, leading to successful completion of the target section at 4020mMD. During the subsequent displacement process, due to increased ECD as the prolonged open hole section and whilst rising of the kill mud weight (KMW) within the annulus caused, well induced severe losses. Subsequently, a multi-stage roll-over mud program was implemented to minimize fluid losses. As an alternative solution, MPW techniques were applied. Upon running the 7" liner, the well was rolled back to a lighter MW, allowing successful execution of managed pressure cementing (MPC). When drilling Well Y, a loss rate of 10 to 16m3/hr. was detected when drilling into the beginning of the 8-1/2" hole section. This was successfully recovered with WSM materials to seal the fractures, by applying SBP of 700 to 800psi during the pump off events with managed pressure drilling (MPD) practices. The well was drilled successfully to a total depth (TD). With MPW techniques in conjunction with the proper application of WSM, well control events were prevented, and costs reduced by eliminating the need to run the 7" liner. These procedures overcome challenges such as controlling ECD, managing fluid loss, controlling gas levels, and successfully completing the drilling and cementing operations. In addition, other real-time monitoring, and analysis methods, such as the Dynamic Formation Integrity Test (DFIT) and Dynamic Pore Pressure Test (DPPT), were utilized to gather valuable data for analysis and future drilling designs.

Abstract Most of the producing oil wells require some form of artificial lift for pumping production fluids to the surface (Bates, Cosad et al. 2004). The Progressing cavity pump (PCP) is considered as one of the most robust types of artificial lift method. About 10 to 15 percent of almost one million wells worldwide produce oil with the help of PCPs. PCPs are very efficient and can handle a range of viscosities, gas-liquid ratios, and solids production. Over the years, one of the most pressing concern of operators using PCPs in their Oil-fields have been, high workover costs and subsequent failures. If the operators do not take care of the PCP installation and take care of the PCP whilst start up, then the PCP efficiency gradually declines over time and the PCP fails at some point of time. This can be attributed to High Torque, Pump Deterioration, Parting of the Rods and other such failures. Due to the failure the financial costs are substantial accompanied by lost production, workover rig costs, replacement costs and intervention costs. To reduce failures operators are investing in real-time surveillance systems to monitor PCP performance using downhole measurements and raise alarms in case of abnormal events such as tripping's or failures. This is done by monitoring various parameters and then action is taken based on the operator's ability to discern the impending failure based on some signature trends. However, more often than usual at this stage it is already too late to do anything that could save the pump or the whole PCP system. Thus, it is important to move from a reactive to a proactive approach. This paper offers such an approach. Specifically, a analytical solution is proposed to proactively calculate and suggest a Torque value within which the PCP should work to deliver the required deliverability from the reservoir. statistical techniques for dimensionality. This analytical solution combines engineering principles with mathematical models to detect a suitable torque long before the PCP crosses this value in an actual well startup scenario. Supervisory control and data acquisition (SCADA) systems and data historians bring about an increased value by optimizing the work procedure or Workflow. Particle swarm optimization (PSO) is one such technique that can be used in conjunction with the workflow to monitor an important parameter such as Rod torque to enable the production engineer to calculate the most suitable hydraulic torque limit for the oil and gas well where a PCP (Progressive cavity pump) is installed. Thus, if a situation arises where the Torque limit is not calculated correctly, this implementation of this analytical solution which is implemented in Python programming language can prevent the wrong Torque value from being calculated and result in saving the PCP pump.

Abstract Pakistan has been a major gas producer and self sufficient to meet domestic needs of the country owing to large hydrocarbon reserves in the sedimentary basins of Pakistan. One of the prominent sources of natural gas in Pakistan is the Sui Structure situated in Sulaiman sub-basin of Indus Basin. The Sui structure is a very large, gentle, ellipsoidal anticline exposed at surface, marked by rocky outcrops forming low hills and cliffs. The Sui gas field, discovered in 1952 by Pakistan Petroleum Limited has evolved into the largest natural gas reservoir in Pakistan, boosting reserves exceeding 9.0 trillion standard cubic feet (TSCF). As the demand of the gas in country escalated, production rates have been increased, leading to the drilling of a total of 115 wells since 1955. However, the gradual decline in pressure within the Sui Main Limestone (SML) reservoir has introduced a multitude of challenges when drilling into a depleted reservoir. These challenges encompass issues such as total circulation loss, reservoir damage, and extended non-productive time thus, requiring innovative solutions to overcome these obstacles. To effectively address these challenges the operator made the decision to utilize underbalanced drilling (UBD) technique for drilling SML, a depleted reservoir characterized by fractured carbonates. However, the presence of sour gas in the reservoir introduced the potential HSE risks associated with handling H2S gas at surface while drilling underbalanced. Considering these risks, it was sought to develop an innovative approach that would allow drilling with a multiphase fluid, maintaining the equivalent circulating density (ECD) slightly above reservoir pressure to prevent hydrocarbon release into the environment. The application of surface closed- loop system not only provided additional back pressure to manage ECD at the bottom but also enabled handling any reservoir flow during static conditions. Successful drilling of the SML formation in the SUI field was achieved by employing the subsequent technology, maintaining an ECD of 0.33 SG until reaching total depth (TD). In addition to drilling, formidable challenges were associated with running and cementing an unconventional liner measuring 9 5/8 inches within the fractured reservoir. Given the size of liner and complex nature of reservoir, conventional methods proved inadequate. Hence, it was devised to run and cement the liner under near-balanced conditions, ensuring that pressure differentials were carefully managed. The utilization of UBD techniques proved effective in drilling the well safely, running the unconventional liner, and successfully cementing it. The operator not only prevented formation losses but also managed to achieve higher rate of penetration compared to conventional methods. The study provides comprehensive details on planning, execution, deliverables, and statistical analysis. The application of this novel technology in an advance manner promises to unlock new horizons in efficient well construction.

Abstract The drilling operator wanted to improve hydrocarbon recovery during drilling a development well using rotating control devices (RCD) for the upper 17-1/2" hole section. The challenge to drill this section was shallow gas that can lead to a kick. To drill these formations conventionally would increase the risk of the well taking a kick that could directly affect the time required to drill the well to its target depth. A closed-loop system was used to anticipate the well taking an influx of shallow gas while drilling this formation. In the event of the well taking an influx, the influx can be safely diverted with RCDs away from rig floor. A closed-loop drilling system was created by installing the Rotating Control Device on top of a 21-1/4" 2K Annular BOP prior to drilling the 17-1/2" section. With this closed-loop system any shallow gas influx can be diverted away from rig floor, thus improving safety to personnel. Another advantage of using a RCD is that the operation can be switched to conventional mode directly without have to rig down the RCD system. Also, using RCD will not interfere with the rig’s well control system. The primary objective of utilizing the RCD was to enhance safety while drilling the development well which contained known hazards already assessed from drilling the previous well. RCD 7800 was utilized to mitigate drilling hazards generated from the loss circulation, gas migration, influx, and the presence of shallow gas. All the objectives were achieved: establishing a closed circulation system, additional safety in drilling a formation containing gas, and ensuring control of return flow.

Abstract The pace of natural gas discoveries globally is growing, but comes with challenges from entrained acid gases, primarily carbon dioxide and hydrogen sulfide. The development of these sour gas fields becomes more complex when there is varying gas composition along the field. Considerations are gas calorific values and corrosive fluids which are detrimental to pipelines and facilities. This paper presents a case study of an integrated asset modeling for three different compartments of varying heating values sharing a joint surface production facility. The aim is to optimize future sale gas contracts, avoid operational problems, and appraise water production effects. The field has three hydraulically isolated compartments, each with unique compositions, with more than 6 Tscf reserves. The gas heating values range from 300 to 700 BTU/CUFT, with CO2 concentrations from 9% to 45%. Field economics requires all three compartments to be produced through a single production platform. This poses many operational challenges, e.g., production strategy to meet sale gas heating values, and pressure constraints to balance gas and water production. A major consideration is the mixing ratio of gas from each compartment. The combined gas composition and produced water will govern acidization effects in the surface facilities, which would need to be minimized. After geological and geophysical modelling, historical production data is matched. Next step is network modeling of surface facilities. The final piece is an economic analysis focused on costs of production, production improvement/remediation costs, and gas sales. The result is the ability to maximize the rate of return on investment while keeping optimized production rates that meet the contractual requirement. Final outputs include gas reserve estimates and the optimized development scheme. The proposed scheme considers workovers, infill wells and gas compression to increase the estimated ultimate recovery and prolong field production life. The final integrated model improved the understanding of the interface between all the components of the system (i.e., reservoir, wellbore, surface, and facility). The model was validated when field production exceeded the maximum historical gas rate and fulfilled the high energy demand requirement. As expected, the field data closely matched the model predictions. The model considered the difficulty in producing the required energy rate and delivery pressure due to bottlenecks in the pipeline and predicted the need for compression due to rising water-gas ratio. The ability to model complex reservoirs and surface production equipment in a single platform is a powerful tool for reservoir management. By carefully modelling the entire system and forecasting, the model transitions from a simple analysis tool to a test bench for altering the production strategy without impacting the actual physical assets. This allows the operator to minimize the cost of ownership and maximize return on investment.

Abstract Well A, a Brownfield offshore oil producer in Brunei, was shut in due to multiple leaks in the tubing. The well was drilled in 2000, so was facing common issues associated with depletion prior to shut-in. Production from the well was restored by installing an innovative thru-tubing retrofit gas lift system, allowing for injection of lift gas below the production packer, while simultaneously restoring tubing integrity by isolating the leaks. The goal of the rigless intervention was to restore tubing integrity by installing an ISO 14310 V0-validated gas-tight straddle across the leaks. The straddle also serves as a retrofit gas lift system, enabling delivery of lift gas below the production packer, just above the horizontal open hole gravel pack section. The straddle directs lift gas down an inner string hung from the lower packer with an installed gas lift mandrel on the bottom of the tail pipe, delivering lift gas below the production packer. The straddle features internal flow paths, allowing produced fluid to flow through the straddle back towards surface. Once installation was complete, the new gas lift valve was installed 200 m TVD (true vertical depth) deeper than the lowermost side pocket mandrel. During the initial well test, lift gas was injected down the casing and entered the production tubing through the leak points and SPM, which were contained within the straddle assembly. The upper and lower packing elements in the straddle directed all gas through the crossflow sub and into the inner string suspended from the lower packer. A slim gas lift valve was connected to the downhole end of the tail pipe. By injecting lift gas in the lower completion, hydrocarbon was unloaded from a deeper depth than would have been possible using conventional gas lift. Within four hours of starting lift gas injection, Well A was flowing steadily with 900 kPa of flowing wellhead pressure (FWHP). The well was then shut in, pending a full well test. This novel approach helped avoid an expensive workover and minimized runs in hole by incorporating the gas lift retrofit system into the straddle isolating the tubing leaks. This installation was the first in Brunei that placed the lift gas injection point beyond the production tubing in a horizontal well. As a result, a well that had been shut in for five years was re-instated and production was further optimized by deepening the lift gas injection point 200 m TVD below the lowermost side pocket mandrel.