SPE Production & Operations
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Published By Society Of Petroleum Engineers

1930-1855

2022 ◽  
pp. 1-13
Author(s):  
Mishiga Vallabhan K. G. ◽  
Marcin Dudek ◽  
Christian Holden

Summary Produced water is a major challenge in the oil and gas industry, especially with the aging of oil fields. Proper treatment of produced water is important in reducing the environmental footprint of oil and gas production. On offshore platforms, hydrocyclones are commonly used for produced-water treatment. However, maintaining the efficiency of hydrocyclones subjected to plant disturbances is a difficult task owing to their compact nature. This paper describes a new experimental test rig built at the Department of Mechanical and Industrial Engineering at the Norwegian University of Science and Technology for testing industrial-scale hydrocyclones. The test setup can emulate first-stage separation and create plant disturbances, such as changes in flow rate, oil concentration, and oil droplet distribution at the inlet of the hydrocyclones. Also, the setup is capable of testing different control algorithms, which helps to maintain the efficiency of hydrocyclones in the presence of such disturbances. The test rig is equipped with various instruments that can monitor such parameters as pressure, flow, temperature, and oil concentration. A typical pressure drop ratio (PDR) control scheme for hydrocyclones is tested in the test rig, which can control the disturbances in the inflow rate. The PDR control scheme does not detect disturbances in the inlet oil concentration and changes in droplet distribution, and these scenarios are shown experimentally in this paper.


2021 ◽  
pp. 1-15
Author(s):  
Kelvin Abaa ◽  
John Wang ◽  
Derek Elsworth ◽  
Mku Ityokumbul

Summary Fracturing fluid filtrate that leaks off during injection is imbibed by strong capillary forces present in low-permeability sandstones and may severely reduce the effective gas permeability during cleanup and post-fracture production. This work aims to investigate the role fracturing fluid filtrate from slickwater has on rock-fluid and fluid-fluid interactions and to quantify the resulting multiphase permeability evolution during imbibition and drainage of the filtrate by means of specialized core laboratory techniques. Three suites of experiments were conducted. In the first suite of experiments, a fluid leakoff test was conducted on selected core samples to determine the extent of polymer invasion and leakoff characteristics. In the second suite, multigas relative permeability measurements were conducted on sandstone plugs saturated with fracturing fluid filtrate. A combination of controlled fluid evaporation and pulse decay permeability technique was used to measure liquid and gas effective permeabilities for both drainage and imbibition cycles. These experiments aim to capture dynamic permeability evolution during invasion and cleanup of fracturing fluid (slickwater). The final suite of experiments consists of adsorption flow tests to investigate, identify, and quantify possible mechanisms for adsorption of the polymeric molecules of friction reducers present in the fluid filtrate to the pore walls of the rock sample. Imbibition tests and observations of contact angles were conducted to validate possible wettability changes. Results from multiphase permeability flow tests show an irreversible reduction in endpoint brine permeability and relative permeability with increasing concentration of friction reducer. Our results also show that effective gas permeability during drainage/cleanup of the imbibed slickwater fluid is controlled to a large degree by trapped gas saturation than by changes in interfacial tension. Adsorption flow tests identified adsorption of polymeric molecules of the friction reducer present in the fluid to the pore walls of the rock. The adsorption friction reducer increases the wettability of the rock surface and results in the reduction of liquid relative permeability. The originality of this work is to diagnose formation damage mechanisms from laboratory experiments that adequately capture multiphase permeability evolution specific to a slickwater fluid system, during imbibition and cleanup. This will be useful in optimizing fracturing fluid selection.


2021 ◽  
pp. 1-8
Author(s):  
Da Zhu

Summary Cyclic steam stimulation (CSS) is one the most effective thermal recovery methods. It is widely used as the primary thermal recovery method to recover heavy oil fields in the Middle East, the Asia-Pacific region, and North and South America. In this paper, a novel dual-directional flow control device (FCD) will be introduced. This FCD technology can allocate accurate steam outflow into the reservoir formation and improve steam quality during the steam injection period and can mitigate steam breakthrough from the neighboring wells during the production period. In the first section, we give a brief introduction on CSS and the main issues encountered in the field operation. A multidirectional flow control nozzle specifically designed for CSS application will be presented. Design philosophy in thermodynamics and hydrodynamics of the nozzle will be discussed in detail. Field performance results, computational fluid dynamics (CFD), and flow loop testing data will be shown to evaluate the performance of the technology. The application of the technology in steam-assisted thermal applications will be introduced. Well-known issues such as erosion and scaling on the FCD tools will be studied in the end.


2021 ◽  
pp. 1-14
Author(s):  
Xuedong Gao ◽  
Qiyu Huang ◽  
Xun Zhang ◽  
Yu Zhang

Summary In our previous article (Gao et al. 2020), a mathematical model including elastic and yield components but not viscous component was developed to predict the wax plug transportation force. In this work, an analytical model was developed to calculate the wax plug transportation force, and the viscous component was introduced into the analytical model to capture some of the time effects. In this analytical model, the viscoelastic behavior of the wax deposit was characterized by a three-parameter model, formulated by adding an additional spring element to the Kelvin-Voight model. The Laplace transformation was used to solve the model. According to the calculated results of the analytical model, the transportation force of the wax plug was observed to slightly increase with time and then tended to level off. To obtain a parameter in the model and verify the model, the pigging experiments were conducted using foam pigs. During the pigging process of the foam pig, the wax plug transportation force in a five-phase wax removal profile was determined by taking the steady wax breaking force from the resistive force of the wax layer. Moreover, the linear increase of the wax plug transportation force per unit contact area with the shear strength of the wax layer was found, as described by the functional relationship in the analytical model. The interfacial lubrication coefficient calculated from the experimental data based on the analytical model is between the coefficient for diesel-prepared deposits and coefficient for oil-A-prepared deposits. Experimental verification results show that the average relative error of the model is 12.47%. Field implication was proposed to illustrate the application of the model and the formation condition of the wax blockage.


2021 ◽  
pp. 1-16
Author(s):  
Tao Zhang ◽  
Ming Li ◽  
Jianchun Guo ◽  
Haoran Gou ◽  
Kefan Mu

Summary The temporary plugging by particles in the wellbore can open new perforation clusters and increase stimulated reservoir volume, but the temporary plugging process of particles is not clear. Therefore, in this paper, we take an ultradeep well in the Tarim Basin as the research object and establish a numerical model based on the coupled computational fluid dynamics-discrete element technology (CFD-DEM) approach, which accurately describes the movement process and mechanism of the temporary plugging particles in the wellbore. Furthermore, the influence of flow rate, concentration of injected particles, and the injected mass ratio of particle size on the temporary plugging effect were studied, respectively. In addition, based on the results of the orthogonal experimental analysis, we obtained the pump rate as the primary factor affecting the effect of temporary plugging, and we recommended the optimal operation parameters for temporary plugging by particles in the field: The pump rate is 2 m3/min, the concentration of the injected temporary plugging particles is 20%, and the ratio of the mass of the injected temporary plugging particles with particle size 1 to 5 mm to the mass of the temporary plugging particles with particle size 5 to 10 mm is 3:1. Finally, a single well that had implemented temporary plugging by particles was used to verify the recommended optimal temporary plugging operation parameters. The research results of this paper provide important guidance and suggestions for the design of temporary plugging schemes on the field.


2021 ◽  
pp. 1-15
Author(s):  
A. Amirov ◽  
F. Hadiaman ◽  
D. Parra ◽  
J. Zeynalov ◽  
A. Kok

Summary In a deviated well in the Caspian Sea, the gas/oil ratio (GOR) increased rapidly in 2017. The result was an oil rate decline with several choke backs to manage GOR buildup. After performing two production-logging jobs, it was confirmed that 76% of the gas production was coming from four upper perforations. The main objective was to perform a gas shutoff (GSO) treatment in two stages to reduce gas production by squeezing polymer into the formation and setting packers at a 59° deviation inside a 9⅝-in. casing for temporary isolation of the middle and lower production sands. Fifteen runs were performed with a tube wire-enabled coiled tubing (CT) telemetry (CTT) system that consists of a customized bottomhole assembly (BHA) that instantaneously transmits differential pressure (DP), temperature, and depth data to the surface through a nonintrusive tube wire installed inside the CT. For the first time in the region, a tension, compression, and torque (TCT) subassembly was deployed to control the entire setting/retrieval process with accurate downhole upward/downward forces. CTT technology was a key element to successfully set two through-tubing inflatable retrievable packers (TTIRPs) by performing casing collar locator correlations at the tubing end, which was 133 and 228 m [measured depth (MD)] shallower from the setting depths. In addition, during the second GSO operation, the GSO gel system crosslink time was modified on the basis of the actual bottomhole temperature (BHT) recorded with the CTT system. Finally, during the third GSO operation, treatment placement was improved, spotting more GSO gel system inside the casing section and avoiding further treatments. After successful placement of the GSO gel system, a drop from 15.5 to 4.5 MMscf/D in gas production was observed (GOR reduction from 11,000 to 750 MMscf/bbl) with an oil rate increment from 1.4 to 6.04 Mbbl/D. Furthermore, after the gas reduction, the operator was able to produce between 1.5 and 2.0 Mbbl/D from other wells that were choked back on the basis of gas handling capabilities limitations. In the short term, GOR reduction sustained at 3,000 MMscf/bbl and 3.0 Mbb/D oil rate. The novelty of using the CTT system and TCT subassembly for real-time monitoring of BHA data proved to be beneficial for positioning two TTIRP, modifying GSO gel system design, placing it precisely across target intervals, and retrieving two TTIRPs that in the end provided direct and positive financial impact for the operator.


2021 ◽  
pp. 1-13
Author(s):  
Zhihui Wang ◽  
Xingkai Zhang ◽  
Ruiquan Liao ◽  
Yu Lei ◽  
Zhigang Fang

Summary The vane swirler separator is widely used in the separation process of wet natural gas owing to a small volume, high efficiency, economy, and environmental protection. In addition to the separation efficiency, the pressure drop is also an important technical and operational index for evaluating the performance of the swirler. In this study, the pressure drop of a swirler vane separator was studied through laboratory experiments and numerical simulations. Through the visualization experimental study of the liquid membrane formation rule and its movement pattern, the reduced gas velocity on the pressure drop was divided into three stages. For a gas superficial velocity less than 5.69 m/s, the effect of gas superficial velocity on the pressure drop was small; for a gas superficial velocity greater than 16.57 m/s, the pressure drop increased significantly with an increase in gas flow rate, and the maximum pressure drop was generated by the two-stage swirler, downstream of which the pressure decreased precipitously. We also observed that when the liquid volume content was less than 3%, the gas superficial velocity was the dominant factor affecting the change in the pressure drop. The average relative error of the pressure drop prediction model based on the conservation of the energy law was 6.16%, which indicated a high calculation accuracy.


2021 ◽  
pp. 1-19
Author(s):  
Aymen Al-Ameri

Summary Sand production is a serious problem in oil and gas wells, and one of the main concerns of production engineers. This problem can damage downhole equipment and surface production facilities. This study presents a sand production case and quantifies sanding risks for an oil field in Iraq. The study applies an integrated workflow of constructing 1D Mechanical Earth Modeling (MEM) and predicting the sand production with multiple criteria such as shear failure during drilling, B index, and critical bottomhole pressure (CBHP) or critical drawdown pressure (CDDP). Wireline log data were used to estimate the mechanical properties of the formations in the field. The predicted sand production propensity was validated based on the sand production history in the field. The interpretation results of some wells anticipated in this study showed that when a shear failure occurs during drilling, the B index is around 2 × 104 MPa or less and the CBHP is equal to the formation pore pressure. For this case, sand control shall be carried out in the initial stage of production. On the other hand, when the shear failure does not exist, the B index is always greater than 2 × 104 MPa, and the CBHP is mostly less than the formation pore pressure. In this case, implementing sand control methods could be postponed as the reservoir pressure undergoes depletion. However, for the anticipated field, sand control is recommended to be carried out in the initial stage of well production even when the CBHP is less than the formation pore pressure since sanding will be inevitable when the reservoir pressure depletes to values close to the initial reservoir pressure. The tentative evaluation of the stress regime showed that a normal fault could be the stress regime for the formations. For a normal fault stress regime, the study explained that when the reservoir permeability is isotropic, an openhole vertical wellbore has less propensity for sand production than a horizontal wellbore. Moreover, when the wellbore azimuth is in the direction of the minimum horizontal stress, the CBHP will be lower than in any other azimuth, and sanding will take place at higher wellbore inclination angles. For the anticipated field, because of the casedhole well completion and the anisotropic reservoir permeability, a horizontal well drilled in the direction of minimum horizontal stress with oriented perforation in the direction of maximum horizontal stress is an alternative method for controlling sand production.


2021 ◽  
pp. 1-8
Author(s):  
T. Jatykov ◽  
K. Bimuratkyzy

Summary An industry-accepted standard for minifrac analysis for evaluating and improving design of hydraulic fracturing treatments originated from the original Nolte analysis (Nolte 1979) of pressure decline, followed by the introduction of Castillo G-function in a Cartesian plot (Castillo 1987). The latter provides a graphical method for the identification of fracture closure pressures and stresses with subsequent derivation of other parameters such as fluid efficiency and fracture geometry. With the introduction of a more advanced consideration of the G-function interpretation for various reservoir conditions (Barree et al. 2007), subdividing the interpretation into calculations based on flow regimes and leakoff modes, this approach has become even more sophisticated. Particularly, interesting flow regimes and leakoff modes during fracture closure include the fracture height recession mode. This mode tends to result in rapid screenout and difficulty in placing high proppant concentrations. Regarding interpretation, the G-function derivative curve for this mode can have more than one plateau, an outcome that is possibly indicative of features that have not been widely considered to date or on which little to no data have been published. This paper presents a case study as an example of such height recession mode, along with a subsequent G-function interpretation and analysis and with consideration of the vertical facies distribution along the wellbore. Considerable attention is paid to the G-function derivative plateau analysis. Three distinctive wells, namely X-1,X-2, and X-3, are discussed. Using this technique can lead to an improved fracture calibration, optimized fracture design, and adoption of a successful completion strategy; additionally, the confirmation of 1D facies distribution can provide new insights into the fracture closure period.


2021 ◽  
pp. 1-11
Author(s):  
Laurie Duthie ◽  
Hussain Saiood ◽  
Abdulaziz Anizi ◽  
Bruce Moore

Summary Successful reservoir surveillance and production monitoring is a key component for effectively managing any field production strategy. For production logging in openhole horizontal extended reach wells (ERWs), the challenges are formidable and extensive; logging these extreme lengths in a cased hole would be difficult enough but is considerably exaggerated in the openhole condition. A coiled-tubing (CT) logging run in open hole must also contend with increased frictional forces, high dogleg severity, a quicker onset of helical buckling, and early lockup. The challenge of effectively logging these ERWs is further complicated by constraints in the completion where electrical submersible pumps (ESPs) are installed, including a 2.4-in. bypass section. Although hydraulically powered CT tractors already existed, a slim CT tractor with real-time logging capabilities was not available in the market. In partnership with a specialist CT tractor manufacturer, a slim logging CT tractor was designed and built to meet the exceptional demands of pulling the CT to target depth (TD). The tractor is 100% hydraulically powered, with no electrical power, allowing for uninterrupted logging during tractoring. The tractor is powered by the differential pressure from the bore of the CT to the wellbore and is operated by a preset pump rate from surface. Developed to improve the low coverage in openhole ERW logging jobs, the tractor underwent extensive factory testing before being deployed to the field. The tractor was rigged up on location with the production logging tool and run in hole (RIH). Once the CT locked up, the tractor was activated and pulled the coil to cover more than 90% of the openhole section, delivering a pulling force of up to 3,200 lbf. Real-time production logging was conducted simultaneously with the tractor activation; flowing and shut-in passes were completed to successfully capture the zonal inflow profile. Real-time logging with the tractor is logistically efficient and allows instantaneous decision making to repeat passes for improved data quality. The new slim logging tractor (SLT) is the world’s slimmest and most compact and is the first CT tractor of its kind to enable production logging operations in openhole horizontal ERWs. The importance of the ability to successfully log these ERWs cannot be overstated; reservoir simulations and management decisions are only as good as the quality of data available. Some of the advantages of drilling ERWs, such as increased reservoir contact, reduced footprint, and fewer wells drilled, will be lost if sufficient reservoir surveillance cannot be achieved. To maximize the benefits of ERWs, creative solutions and innovative designs must be developed continually to push the boundaries further.


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