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Romer, Michael Christopher (ExxonMobil Upstream Research Company) | Spiecker, Matt (ExxonMobil Upstream Research Company) | Hall, Tim James (ExxonMobil Upstream Research Company) | Dieudonne, Raphaël (Hydro Leduc) | Porel, François (Hydro Leduc) | Jerzak, Laurent (Hydro Leduc) | Ortiz, Santos Daniel (KSWC Engineering & Machining) | King, George Randall (KSWC Engineering & Machining) | Gohil, Kartikkumar Jaysingbhai (KSWC Engineering & Machining) | Tapie, William (Deteq Services) | Peters, Michael (MTI) | Curkan, Brandon Alexander (C-FER Technologies)
Summary What do you do after plunger lifting? What if lift gas is not readily available or your liquid level is around a bend? What can you do with a well that has low reservoir pressure, liquid-loading trouble, and fragile economics? Do you give up on the remaining reserves and advance to plugging and abandonment? These questions were considered, and the answers were found to be unsatisfactory. This paper will describe the development and testing of a novel wireline-deployed positive-displacement pump (WLPDP) that was invented to address these challenges. Artificial-lift (AL) pumps have historically been developed with high-producing oil wells in mind. Pumps for late-life wells have mostly been repurposed from these applications and optimized for reduced liquids production. The WLPDP development began with the constraints of late-life wells with the goal of addressing reserves that conventional AL methods would struggle to produce profitably. Internal and industry-wide data were first reviewed to determine what WLPDP specifications would address the majority of late-life wells. The primary target was gas wells, although “stripper” oil wells were also considered. The resulting goal was a pump that could deliver 30 BFPD from 10,000-ft true vertical depth (TVD). The pumping system must be cost-effective to be a viable solution, which led to several design boundaries. Pumps fail and replacement costs can drive economics, so the system must be deployable/retrievable through tubing. The majority of new onshore wells have tortuous geometries, so the system must be able to function at the desired depth despite them—without damaging associated downhole components. The system should use as many off-the-shelf components and known technologies as possible to reduce development costs and encourage integration. Finally, the pump should be able to handle a variety of wellbore liquids, produced gases, and limited solids. The WLPDP was designed to meet the established specifications and boundary conditions. The 2.25-in.-outer-diameter (OD) pump is deployed through tubing. and powered with a standard wireline (WL) logging cable. The cable powers a direct-current (DC) motor that drives an axial piston pump. The piston pump circulates a dielectric oil between two bladders by means of a switching valve. When each bladder expands, it pressurizes inlet-wellbore liquids, pushing them out of the well. Produced gas flows in the annulus between the tubing and production casing. The intake/discharge check valves and bladders are the only internal pump components that contact the wellbore fluids. The WLPDP system was able to meet the design-volume/pressure specifications in all orientations, as confirmed through laboratory and integration testing. Targeted studies were conducted to verify/improve check-valve reliability, gas handling, elastomer suitability, and cable-corrosion resistance. The results of these and related studies will be discussed in the paper.
Summary Working in the oil industry comes with unique challenges and risks, and so extra precautions and safety measures coupled with strict environmental compliance must be applied. Contrary to the common belief that strict safety enforcement could hinder smooth operations, the deployment of new technologies and enhanced solutions of processes has enabled operational excellence (OE) and improved safety performance. In this paper, we demonstrate health, safety, and environment performance improvement through implementing two main initiatives: The first category has initiatives that require less intervention or personnel; for example, the deployment of cableless pressure sensors or permanent monitoring systems in key wells to ensure continuous real-time pressure data to monitor reservoir pressure. The second category has initiatives that mitigate traditional health, safety, and environment risks; for example, through use of multiphase flow meters (MPFMs) to collect accurate and continuous flow measurements instead of traditional well testing. Optimizing operations costs while maintaining a high-level of safety is achieved through a dedicated team working in a state-of-the-art Production Operations Surveillance Hub (POSH), which enables the monitoring of wells in real time, making production optimization decisions, and ensuring a high level of well integrity via close monitoring of wells and assets.
Summary Seawater injection is widely used to maintain offshore-oil-reservoir pressure and improve oil recovery. However, injecting seawater into reservoirs can cause many issues, such as reservoir souring and scaling, which are strongly related to the seawater-breakthrough percentage. Accurately calculating the seawater-breakthrough percentage is important for estimating the severity of those problems and further developing effective strategies to mitigate those issues. The validation of using natural-ion boron as a tracer to calculate seawater-breakthrough percentage was investigated. Boron can interact with clays, which can influence the accuracy in seawater-breakthrough calculation. Therefore, the interaction between boron and different clays at various conditions was first studied, and the Freundlich adsorption equation was used to describe the boron-adsorption isotherms. Then, the boron-adsorption isotherms were coupled into the reservoir simulator to investigate the boron transport in porous media, and the results in turn were further analyzed to calculate the accurate seawater-breakthrough percentage. Results indicated that boron adsorption by different clays varied. pH value of solution can significantly influence the amount of boron adsorbed. As a result, the boron-concentration profile was delayed in coreflood tests. The accuracy of the new model was verified by convergence rate tests and comparison with analytical results. Furthermore, model results fit well with experimental data. On the basis of the reservoir-simulation results, the boron-concentration profile in produced water can be used to calculate the seawater-breakthrough percentage by considering the clay-content distribution. However, the seawater-breakthrough point cannot be determined by boron because the boron concentration is still at the formation level after seawater breakthrough due to boron desorption.
An experimental number used in fluid flow to predict the flow velocity at which the flow regime moves from laminar flow through a transition range and into turbulent flow. It is the dimensionless ratio of inertial forces to viscous forces in flowing fluids. It may be viewed as a ratio of the shear stress due to turbulence to the shear stress due to viscosity. Flow with a Reynolds number less than 2000-4000 is laminar flow; that with a Reynolds number greater than 2000-4000 is turbulent flow.
Abstract Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.
Wu, Yinghui (Silixa LLC) | Hull, Robert (Silixa LLC) | Tucker, Andrew (Apache Corp.) | Rice, Craig (Apache Corp.) | Richter, Peter (Silixa LLC) | Wygal, Ben (Silixa LLC) | Farhadiroushan, Mahmoud (Silixa Ltd.) | Trujillo, Kirk (Silixa LLC) | Woerpel, Craig (Silixa LLC)
Abstract Distributed fiber-optic sensing (DFOS) has been utilized in unconventional reservoirs for hydraulic fracture efficiency diagnostics for many years. Downhole fiber cables can be permanently installed external to the casing to monitor and measure the uniformity and efficiency of individual clusters and stages during the completion in the near-field wellbore environment. Ideally, a second fiber or multiple fibers can be deployed in offset well(s) to monitor and characterize fracture geometries recorded by fracture-driven interactions or frac-hits in the far-field. Fracture opening and closing, stress shadow creation and relaxation, along with stage isolation can be clearly identified. Most importantly, fracture propagation from the near to far-field can be better understood and correlated. With our current technology, we can deploy cost effective retrievable fibers to record these far-field data. Our objective here is to highlight key data that can be gathered with multiple fibers in a carefully planned well-spacing study and to evaluate and understand the correspondence between far-field and near-field Distributed Acoustic Sensing (DAS) data. In this paper, we present a case study of three adjacent horizontal wells equipped with fiber in the Permian basin. We can correlate the near-field fluid allocation across a stage down to the cluster level to far-field fracture driven interactions (FDIs) with their frac-hit strain intensity. With multiple fibers we can evaluate fracture geometry, the propagation of the hydraulic fractures, changes in the deformation related to completion designs, fracture complexity characterization and then integrate the results with other data to better understand the geomechanical processes between wells. Novel frac-hit corridor (FHC) is introduced to evaluate stage isolation, azimuth, and frac-hit intensity (FHI), which is measured in far-field. Frac design can be evaluated with the correlation from near-field allocation to far-field FHC and FHI. By analyzing multiple treatment and monitor wells, the correspondence can be further calibrated and examined. We observe the far-field FHC and FHI are directly related to the activities of near-field clusters and stages. A leaking plug may directly result in FHC overlapping, gaps and variations in FHI, which also can be correlated to cluster uniformity. A near-far field correspondence can be established to evaluate FHC and FHI behaviors. By utilizing various completion designs and related measurements (e.g. Distributed Temperature Sensing (DTS), gauges, microseismic etc.), optimization can be performed to change the frac design based on far-field and near-field DFOS data based on the Decision Tree Method (DTM). In summary, hydraulic fracture propagation can be better characterized, measured, and understood by deploying multiple fibers across a lease. The correspondence between the far-field measured FHC and FHI can be utilized for completion evaluation and diagnostics. As the observed strain is directly measured, completion engineering and geoscience teams can confidently optimize their understanding of the fracture designs in real-time.
Abstract Low-frequency distributed acoustic sensing (LF-DAS) has been used for hydraulic fracture monitoring and characterization. Large amounts of DAS data have been acquired across different formations. The low-frequency components of DAS data are highly sensitive to mechanical strain changes. Forward geomechanical modeling has been the focus of current research efforts to better understand the LF-DAS signals. Moreover, LF-DAS provides the opportunity to quantify fracture geometry. Recently, Liu et al. (2020a;2020b) proposed an inversion algorithm to estimate hydraulic fracture width using LF-DAS data measured during multifracture propagation. The LF-DAS strain data is linked to the fracture widths through a forward model developed based on the Displacement Discontinuity Method (DDM). In this study, we firstly investigated the impacts of fracture height on the inversion results through a numerical case with a four-cluster completion design. Then we discussed how to estimate the fracture height based on the inversion results. Finally, we applied the inversion algorithm to two field examples. The inverted widths are not sensitive to the fracture height. In the synthetic case, the maximum relative error is less than 10% even when the fracture height is two times of the true value. After obtaining the fracture width, the fracture height can be estimated by matching the true strain data under various heights with a strong smooth weight. The error between the calculated strain and true strain decreases as the height is getting close to the true value. In the two field examples, the temporal evolutions of both width summation of all fractures and the width of each fracture show consistent behaviors with the field LF-DAS measurements. The calculated strain data from the forward model matches well with the field LF-DAS strain data. The results demonstrate the robustness and accuracy of the proposed inversion algorithm.