Open Hole Section Research Articles

Application of distributed acoustic sensing technology in deep shale gas exploration

Abstract In the past decade, the exploration and development of deep shale gas usually adopted geophone acquisition for vertical seismic profile (VSP) to improve the accuracy and resolution of seismic data. However, it’s very hard to use the 10-20m level spacing geophones to meet the resolution of 2-5m thin reservoir. Distributed acoustic sensing (DAS) technology has been widely used in the oil and gas field due to its advantages of high density and high efficiency acquisition, especially in vertical seismic profile and dynamic monitoring. We have acquired zero offset VSP by DAS and geophone for the first time in deep shale gas wells at home, and successfully overcome the coupling problem in open-hole sections. Vibrators are used as sources for multiple stacking to improve the signal-to-noise ratio (SNR) of DAS VSP. The records show DAS has significant advantages in frequency, SNR and wavelet consistency. After data processing, the layer velocity characteristics of DAS VSP are more obvious. DAS VSP corridor stack has a high degree of consistency with the synthetic record and seismic profile, and the resolution of the reservoir was higher than geophone.

An Integrated Solution in Utilizing Active Magnetic Ranging to Seal Off Underground Gas Storage: Theoretical Analysis and Field Test

Summary In this paper, we describe a comprehensive technology based on an active magnetic ranging system (AMR) for sealing off the cement plug (CP) in the open hole (OH) section of the wellbore below the existing CP for underground gas storage. Utilizing depleted oil and gas reservoirs for natural gas storage is an important approach toward achieving carbon neutrality. Sealing off old wellbores is prioritized according to relevant standards. The challenge with OHs with CP is that there are no magnetic beacons in the wellbore, and the extent of compaction is unknown. Accurate placement of the seal-off CP is crucial because current technical methods, such as electromagnetic and acoustic waves, have limitations. Magnetic ranging technology, which is mature and widely used for wellbore interceptions or collision avoidance, requires magnetic beacons such as steel casing, drillpipes, or bottomhole assemblies left in the borehole. On the other hand, acoustic positioning techniques are applicable but presently complex to run operationally. In this paper, we propose a comprehensive control technology. It starts by measuring the positional relationship between the subject wellbore (SW) and a magnetic beacon wellbore (MBW) using AMR. The data are then used in combination with additional skew data along with associate positional uncertainty or ellipse of uncertainty (EOU) to determine the location of the target wellbore (TW) and the MBW. By calculating the relative positional relationship between the SW and the TW, OH reentry below CP can be achieved within the EOU below the sidetracking point. After reentry, specific work such as crushing, element logging, caliper logging, and full hydrocarbon gas detection is performed to verify if the TW is still in the original position and if the caprock is properly squeezed and sealed off. The comprehensive technique or method was tested on five wells in the Bohai Bay, successfully assessing the position of the OH wellbore and reentering below the CP. The process system expands the field of AMR and demonstrates significant industrial application value. It provides a new means of sealing off complex old wells.

Reverse cementing: How can it work?

Primary cementing of casing strings is a necessary well construction operation where the annulus behind the string is displaced to a cement slurry. Cementing by reverse-circulation involves injecting cementing fluids directly to the annulus from surface, which can reduce the circulation pressure exerted onto the open-hole section during placement. We study density-unstable reverse-circulation displacement flows involving non-Newtonian fluids in near-vertical, eccentric annuli and use a semi-analytical displacement model to assess whether the interface between displaced and displacing fluids will elongate (unsteady displacement), or remain compact as cementing fluids are pumped down the well (steady displacement). We use the displacement model to study how casing eccentricity and fluid viscosity hierarchy impact the displacement classification. We find that typical field values tend to associate with unsteady displacements, particularly in regions of poor casing centralization, and for displacements involving “traditional” drilling mud, spacer and cement slurry properties. Improving casing centralization, increasing the displacing fluid viscosity and reducing the fluid density difference all act to stabilize the displacement. Similarly, increasing the imposed flow rate can also reduce the rate at which the interface elongates by enhancing the viscous stresses during placement. We compare selected scenarios to displacement simulations performed with the 2-dimensional gap-averaged (2DGA) model, and find qualitative agreement between the 2DGA results and our displacement classification predictions. While our study shows that it is possible to make density-unstable reverse-circulation displacements steady, we note that the identified measures are likely to increase the circulation pressures, which may offset an important benefit of reverse-circulation cementing.

Borehole Condition and Limit Pressure Differential Analysis in Carbonate Reservoirs

In deep carbonate reservoirs, testing and production with open-hole completion can help release the maximum production capacity. However, because the reservoir is subjected to high in situ stress, if the test pressure differential is too large, the wellbore collapse and instability will occur easily, causing downhole accidents. Therefore, it is necessary to determine the state of the borehole during the open-hole test in the carbonate reservoir and analyze the ultimate test pressure differential accordingly to ensure test safety. Considering the characteristics of open-hole completion, based on the mechanical properties of the carbonate reservoir and the stress distribution around the borehole during testing, a calculation method of the elastic zone, plastic zone, and residual failure zone around the open-hole wellbore was proposed. Regarding actual engineering data, a criterion for the overall stability of the open-hole section had been established from three aspects: the volume ratio of the plastic zone; the failure zone around the wellbore; and the failure angle on the borehole wall. According to this criterion, it is possible to determine the ultimate pressure differential during the open-hole test process and provide theoretical support for designing the open-hole completion test and production parameters for deep carbonate reservoirs.

Study Reviews Multilateral Installation Improvements on the North West Shelf

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32910,“A Decade of Multilateral Technology Installation Improvements Down Under,” by Stefano Cappiello and Adam Pasicznyk, SPE, Halliburton. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. _ Multilaterals wells on the North West Shelf of Australia have been installed for over a decade. An overview of the well architecture, technology evolution, reliability, and efficiency of these operations is presented in the complete paper. The study is focused on subsea multilateral campaigns, where multiple global and regional first installations took place in mature fields. Introduction Multilateral developments in Australia mainly have been completed off subsea installations, with fewer performed from jack-up rigs. These multilateral completions mostly have been installed with the junction located in the producing reservoir sands. Technology Advancement of Multilaterals (TAML) Level 5 completions have successfully been deployed. The authors classify related systems as follows, with the most attention paid in the synopsis to the final two classes: - Generation One (Field A) - Generation Two (Field B) - Generation Three (Field C) - Generation Four (Field A) General Multilateral Well Design Because of sand production within the reservoir, these applications typically require a TAML Level 5 completion system. These systems deliver hydraulic and mechanical isolation at the junction through the completion. The junction is isolated above and below by production packers and by swell packers in the lateral. The junctions typically are installed horizontally within the reservoir. The original general requirements to construct Level 5 multilateral junctions included the following: - Ability to construct a Level 5 Junction in the 9⅝-in. casing or liner - Ability to run a landing profile or coupling as part of the 9⅝-in. production casing or liner - Ability to run and orient a premilled window at depth - Drill-out 8½-in. openhole section into the mainbore and into the lateral - Junction installed within the reservoir at high angle - Window milling to be performed in one trip - Lateral completion to be installed in one trip - Compressive strength rating capable of running screen sections over 2 km As the operators began to adopt multilateral technology in Australia, the following requirements were incrementally added: - Ability to deliver a Level 5 multilateral system in an existing well - Ability to deliver a trilateral well - Improve efficiency and reduce installation time

Estimation of Surge and Swab Pressures While Tripping for Minimizing Excessive Drilling Problems

Surge and swab pressures result from pipe movement upward/downward during drill string reciprocation and tripping. surge and swab create costly drilling concerns such well kick, formation breakage, and lost circulation. This study aims to find the optimum pipe tripping speed to avoid surge and swab issues, particularly in lost circulation zones. Also, to determine how drilling factors and well bore geometry affect surge and swab pressures. Mud rheology, mud properties, hole diameters, drill pipe diameter, and bottom hole assembly (BHA) dimensions were also analyzed. Dynamic surge and swab model was employed to simulate two case studies in Rumaila Iraqi oilfield. The findings indicated that the tripping speed is the most effective variable on surge and swab pressures. Annular clearance and BHA design have also a major effect on the surge and swab pressures. For the first case study, it is found that whenever the mud weight is far from the pore pressure and fracture pressure gradients, the 5" drill pipe can be tripped in/out of lost circulation formation (Shuaibba formation) at optimum tripping speed of (80 ft/min) without surge/ swab related problems. The reason is that the generated surge pressures (6110-6300 psi) are below the fracture pressure (7100-7400 psi). The results also showed that tripping 5" drill pipe within a maximum running speed of 80 ft/min in (8.5") open hole section through Tanuma formation till Rumaila formation causes a surge pressures of (4650-5050 psi) which is still below the fracture pressures of formations (4750-5660 psi). the results of the second case study (S-shaped well) revealed that the optimum tripping speed of the drill string in the (12.25") open hole through Dammam and Hartha formations is (90 ft/min). it is also concluded that pulling out of hole (POOH) process must be carried out more carefully than the running process since the mud density is near the pore pressure gradient. The results of this study can be further used to improve the drilling efficiency in Rumaila oil field with decreasing non-productive time (NPT) by employing the appropriate tripping speed and optimal drilling operations.

Flowback Rates for Pump-In/Flowback Test

Summary The pump-in/flowback test (PIFT), often referred to as the diagnostic fracture injection test (DFIT) with flowback, offers notable advantages in terms of time efficiency and accuracy, particularly in the context of low-permeability formations. The key to the success of this test lies in the careful selection of an optimal flowback rate to yield meaningful results. The fundamental assumption underlying the pressure analysis of these tests is the uniform closure of fractures during the flowback phase, which is considered the default fracture closure mode in current analyses. In this study, we present evidence that challenges the validity of this assumption, highlighting instances where unsuitable flowback rates can lead to nonuniform fracture closure and result in abnormal pressure data. To address this challenge, we identify different closure modes through the signature of fracture closure in the excessive bottomhole pressure decline curve. Subsequently, we propose an optimal range of flowback rates using a scaling analysis approach to obtain a uniform closure mode in an extended openhole section of a vertical well. Our method has been rigorously validated through 3D numerical simulations and field studies, enhancing its reliability and applicability. This approach helps operators to conduct effective tests in complex situations, overcoming a barrier to widespread test application.

Analysis of Surge and Swab ECD of Herschel Bulkley Fluids in Rumaila Iraqi Oil Field

Surge and swab pressures are frequently produced during various stages of well construction, including casing running and tripping operations. Managing downhole pressure within the mud window is crucial for mitigating the risks associated with drilling operations including wellbore failure, lost circulation, kicks, and well control issues. The primary objectives of this study are to emphasize the theoretical foundation of surge and swab pressures, forecast the optimum pipe and casing tripping speeds, as well as identify the changes in surge and swab pressures (i.e., equivalent circulating density-ECD) for both open-ended and close-ended drill strings. To achieve these goals, a steady state surge and swab model was used to simulate a case study in the Rumaila oil field, located in Southern Iraq, by utilizing landmark-well plan software. The results of this study support the evidence that the string trip speed plays a substantial role in controlling the swab and surge pressures. It was found that pulling out the 5" drill string from the 12 1/4" open hole section drilled with a 9.51 ppg water-based mud at a speed of 10 sec/stand resulted in a swab ECD below the formation pore pressure against all formations, thus resulting in a kick. Moreover, it was found that the annular clearance had a significant impact on the surge and swab ECD whereas the surge ECD at the bit was bigger than that obtained at the previous hole casing shoe. For example, in our case study pulling speeds ranging from 10-190 sec/stand for the 9 5/8" casing could cause the swab ECD to be below the formation pore pressure gradient at total depth (TD), which is 9.23 ppg. While it was safe to run the same casing through the same interval within 55-190 sec/stand. Furthermore, the results emphasized high trip speeds ranging between 10-30 sec/stand, where for close-ended drill strings, greater surge ECD was observed compared to the open-ended ones. The surge ECD of a 5" close-ended drill string at 30 sec/stand (60 m/min) at bit was 9.92 ppg, while an open-ended string at the same speed was 9.9 ppg.

Retarder design for long open-hole well cementing through the interfacial adsorption

In the long open-hole section well-cementing, cementing fluids frequently lose their effectiveness because of high temperature and slow development of the strength of the top cement slurry. In the present study, this problem has been addressed with the high temperature polymer retarder (HTX-1) based on interfacial adsorption because the cement slurries can be characterized as colloidal suspensions. The HTX-1 was characterized through Fourier transform infrared spectroscopy (FTIR), nuclear magnetic resonance (NMR) and thermogravimetric analysis (TGA). Then, the performance of the HTX-1in the cement slurry was evaluated in our laboratory. It was found that the molecular structure of the designed HTX-1 by FTIR and MNR spectroscopy contain the characteristic functional groups of the four monomers. The HTX-1 has only 4.5% mass loss when the temperature is less than 332 ℃. The concentration sensitivity coefficient of the HTX-1 is in the range of 0.48～1.73, and the maximum temperature sensitivity coefficient of the HTX-1 is 6.2%. The 24 h compressive strength of the top cement column at temperatures between 60 ℃ and 100 ℃ is at least 10.6 MPa. This experimental investigation shows that the new retarder has high temperature resistance, low sensitivity and wide application range of temperature. The thickening time of cement slurry can be adjusted while meeting the required strength of top section in deeper wells through changing addition amount of the HTX-1.

HYDRAULIC COILED TUBING TRACTOR TECHNOLOGY EXTENDS THE ACCESSIBILITY OF COILED TUBING IN HORIZONTAL WELLS, ALLOWING BETTER WELL INTERVENTION – CASE STUDY

Recent advances in drilling technology have resulted in longer horizontal wells and have increased the complexity of well completion; the well intervention is becoming more challenging. Conventional techniques are no more adequate to access in long openhole horizontal sections when using coiled tubing to perform intervention works such as stimulations, logging and zonal isolation. This essay was created to assess the capability of a coiled tubing string to reach the desired depth in a projected long horizontal well. The scope of this essay is to provide a complete set of simulations to predict the tubing forces for two proposed different diameters of openhole section. Such simulations can serve as guidelines for completing the well.

Reservoir and Fracture Characterization for Enhanced Geothermal Systems: A Case Study Using Multifractured Wells at the Utah Frontier Observatory for Research in Geothermal Energy Site

Summary For enhanced geothermal systems (EGS), multistage hydraulic fracturing along a deviated or horizontal well is a key technology used to create a high-conductivity fracture network between injection and production wells in deep, low-permeability geothermal reservoirs. The purpose of the created fracture network is to allow for the efficient transfer of fluid, heated by the geothermal reservoir, from the injection to the production well; therefore, well spacing (between injection and production wells) and hydraulic fracturing must be designed not only to promote connectivity between well pairs but also to mitigate thermal short-circuiting and thermal breakthrough. Analysis of post-fracture pressure decay (PFPD) data measured after each stage of a hydraulic fracturing treatment can be used to provide critical reservoir and fracture parameters required for well and hydraulic fracturing design optimization; this method provides a low-cost alternative and complementary approach to in-situ observation techniques, such as core-through experiments, fiber optics, or image logs in offset wells. Until now, PFPD has primarily been applied to multifractured horizontal wells (MFHWs) completed in low-permeability hydrocarbon reservoirs. The goal of this study is therefore to develop a methodology to estimate fracture and reservoir parameters using stage-by-stage PFPD data associated with EGS projects. An analytical model is proposed herein to estimate fracturing fluid efficiency, fracture length, average fracture aperture, average fracture conductivity, and reservoir permeability for different possible fracture geometries in EGS reservoirs. PFPD data collected for three hydraulic fracture stages in the injection well at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed to demonstrate the practical application of the proposed method. The results of this study indicate that, due to the presence of natural fractures in the target (granitic) reservoir, the hydraulic fracturing treatment (using slickwater) in the openhole section resulted in low fracturing fluid efficiency and small hydraulic fractures. In contrast, hydraulic fracturing treatments conducted in the perforated casedhole wellbore resulted in higher fracturing fluid efficiency and created larger hydraulic fractures even with smaller injected volumes. The results of the PFPD analysis were confirmed using a Formation MicroScanner image log and microseismic data collected during each stage of hydraulic fracturing.

A coupling prediction model of annular pressure build-up for deepwater oil and gas wells during transient-state testing

To accurately predict annular pressure build-up of deepwater high pressure-high temperature oil and gas wells during the transient-state testing, a coupling prediction model of trapped & untrapped annular pressure build-up is proposed. For the short-term process of gas well transient testing, a wellbore transient heat transfer model has been established. Then the improved coupling model of trapped & untrapped annular pressure build-up is established, which is not only novelly considering fluid thermodynamic properties (isobaric expansion coefficient and isothermal compression coefficient) under high pressure-high temperature conditions and annulus fluid mass changes of untrapped annulus, but also considering annulus volume changes. For precise coupling calculating the annular pressure build-up, the annulus is divided into infinitesimal grid cells along well depth. The impact of different considering factors, testing times, testing production rates, formation permeability and cement sheath sealing positions on the annular pressure build-up in the model is investigated. The results show that conventional models (high pressure-high temperature properties and mass changes of the fluid are not considered) will greatly overestimate the annular pressure build-up; as the testing time increases, the impact of untrapped annulus fluid mass changes on the annular pressure build-up will gradually take the dominant role; reasonably optimizing the setting of untrapped annulus open hole section in high permeability formations and increasing the distance between cement sheath and the upper casing shoe can effectively relieve the increasing annular pressure build-up. These findings can achieve accurate prediction of trapped and untrapped annular pressure build-up, and play an important role in guaranteeing the wellbore integrity and safety of deepwater oil and gas wells during transient-state testing.

Creep monitoring and parameters inversion methods for rock salt in extremely deep formation

When underground salt caverns are used for natural gas storage, the pressure difference between the inside and outside of the cavern will cause continuous creep deformation of the surrounding rock. Understanding the creep characteristics and constitutive model parameters of rock salt in actual formations is of great significance for guiding the construction and safe operation of gas storage facilities. In this paper, a creep contraction calculation model for slender cylindrical rock salt caverns was established firstly, based on the theory of complex variables and viscoelasticity. This model can calculate the radial displacement of the surrounding rock at any moment on the cross-section of the rock salt wellbore. Subsequently, two indirect monitoring methods for deep rock salt creep using the open hole section of the well were proposed based on this model, which involves using the cavern pressure change after wellhead closure and the liquid overflow rate after wellhead opening to indirectly reflect the deformation of underground rock salt. These two sets of field experiments can be used together to determine the values of the constitutive model parameters of rock salt creep under actual stress conditions. This theoretical framework was applied in the Ningjin Salt Cavern Gas Storage Project in China. Pressure monitoring was conducted for 150 days, and wellbore fluid overflow was measured for 45 h in a rock salt well at a depth close to 3000 m. The calculated results showed good agreement with the field monitoring data, and the parameters of the Burgers creep model for rock salt under actual conditions were determined. This demonstrates the strong feasibility of the monitoring method and the validity of the computational model. Finally, using the obtained creep parameters, a quantitative analysis of the creep contraction of the wellbore was performed considering factors such as internal pressure, in situ stress, and Poisson's ratio of the rock salt.

Fracturing criterion of rock hydrofracturing considering pore pressure effect

Traditional hydraulic fracturing theory believes that as the initial pore pressure increases, the breakdown pressure of the rock will decrease. Previous experimental studies have shown that the breakdown pressure of rock hydraulic fracturing may increase with the increase of initial pore pressure (gradient), which cannot be explained by traditional theory. The current understanding of the effect of pore pressure and its gradient during hydraulic fracturing is still unclear. In this study, the pore pressure effect of rock hydraulic fracturing is analyzed based on a large number of macroscopic and microscopic phenomena of rock hydraulic fracturing in the previous study. Then, a new fracture criterion of rock fracturing is built considering the pressure-gradient effect. This new fracture criterion can reflect the main influence factors, including the rock particle size, porosity, pumping flow, inner diameter of open hole section, length of main fracture, height of main fracture (or length of open hole section), fluid viscosity, pore pressure, minimum initial in situ stress and rock tensile strength. The new fracture criterion is examined by the rock fracturing experiment which considering the pressure-gradient effect. The results show that the proposed fracture criterion considering the pore pressure effect can well predict the breakdown pressure of rock, and the prediction trend is consistent with the experimental results. The average error is less than 1% when adopting the present fracture criterion. The parameter sensitivity of the fracture criterion is analyzed. Results show that the fracture pressure increases with the rock porosity and this trend becomes more apparent with a larger initial pore pressure. It shows that the fracture pressure increases with the pumped flow rate. Besides, it shows that the fracture pressure decreases when increasing the particle size of the rock, but the decreasing trend gradually slows down. The research results can provide a theoretical basis for the mechanism of rock hydraulic fracturing and the structural modification effect of fluids in rock engineering.

Risk Analysis and Scheme Optimization of Sand Control String Running in Extended Reach Horizontal Well

Due to the structure of the wells and other factors, the sand control string in offshore extended-reach wells is subjected to great friction resistance and even buckling phenomenon when being lowered, which ultimately leads to the failure of the string to be lowered in place. Based on elastoplastic and other relevant theories, this paper took an extended reach horizontal well in an oilfield in the South China Sea as an example and analyzed the friction and wellhead suspension weight of different well structures and completion string combinations in the process of running and finally carried out the risk analysis of the running string and the optimization of completion scheme. The results show that the friction resistance of the four-hole structure (8 1/2″) is lower than that of the five-hole structure (6″). Among them, an 8-1/2″ open hole 5-1/2″ high-quality screen is preferred, and a 6″ open hole 4″ high-quality screen is preferred. The friction coefficient in the open hole section is less helpful in improving the running safety of the sand control string, while reducing the friction coefficient in the casing is more obvious to reduce the friction. The results can provide guidance for the running of the screen and control string in the extended reach horizontal well.

Research on the Influence of a Cuttings Bed on Drill String Friction Torque in Horizontal Well Sections

Horizontal well drills are difficult to operate and require high borehole cleaning operations. The impact of cuttings accumulation on friction and torque cannot be ignored. In the process of horizontal well drilling, it is very easy to form a cuttings bed in the highly inclined eccentric annulus. The formation of the cuttings bed will not only increase the friction torque but also have a greater impact on the annulus flow. Based on the application of gas drilling in horizontal wells, this paper uses laboratory experiments to study the influence of cuttings with different particle sizes and lithology on the friction coefficient between the drill string and the borehole wall of the horizontal well section. In addition, in view of the difficulty in the migration of cuttings in gas drilling horizontal wells and the formation of cuttings deposits, this paper carries out an experimental study on the effect of the cuttings bed on drill pipe coating height and cuttings bed thickness on friction coefficient. Experimental results show that the friction coefficient of gas drilling horizontal wells is about 0.44–0.58. When the coating height of the cuttings on the drill pipe exceeds a certain value (26 mm), the friction coefficient tends to be stable, but its value is as high as about 0.55. When the thickness of the accumulation of cuttings exceeds a certain value (10 mm), the subsidence hindering effect between the particles in the cuttings bed is weakened, so the friction coefficient of the casing section and the open hole section tends to be stable, about 0.53.

Research on dynamic prediction of tubular extension limit and operation risk in extended-reach drilling

Extended-reach wells have been widely applied to efficient development of oil and gas resources in complex areas such as oceans, beaches, lakes and mountains. Extended-reach drilling has the characteristics of many constraints, high implementation difficulty and high operation risk, and the accurate prediction of tubular extension limits and operation risks is very significant for safe drilling. Firstly, local tubular deflection curves and additional contact forces due to discontinuity effects are firstly deduced, and an amended torque & drag model of tubular strings is built. Secondly, a dynamic inversion method of friction factors was presented by introducing the weight function related to well depth and considering the difference of friction factors on cased and open-hole sections. Next, a dynamic prediction of tubular extension limit and operation risk is built by combining the amended tubular mechanical model, inversion model of friction factors. At last, the above theoretical models are applied to a case study. The results indicate that curvature discontinuity and stiffness discontinuity increase contact forces obviously in build-up and azimuth turning sections, which further increase friction force and torque a lot. The long-term, short-term and real-time tubular extension limits and operation risks can be obtained by setting different values of p.

Study Reviews ESP Performance in High-Viscosity Applications

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31839, “Understanding ESP Performance Under High-Viscosity Applications and Emulsion Production,” by Luiz Pastre, SPE, Jorge Biazussi, and William Monte Verde, University of Campinas, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ Despite its common use as an artificial lift method for heavy-oil developments, electrical-submersible-pump (ESP) system performance in high-viscosity applications is not fully understood. Failure to understand challenges to equipment performance in such conditions can lead to operational inefficiency and equipment failures. The complete paper presents results of single-phase and multiphase tests performed by researchers at the University of Campinas. It also presents operational data, lessons learned, and examples of failures gathered over 10 years of ESP operation in the Peregrino field, a highly viscous, heavy-oil field offshore Brazil operated by Equinor. Peregrino Field The field was discovered in 1994 in the southern part of the Campos Basin offshore Brazil. The discovery lies in shallow waters approximately 120 m deep in Block BM-C-7. Although a large amount of recoverable oil in place (300 million– 600 million bbl) was confirmed, the technology to properly develop the field was not available. A detailed development plan was created to optimize Peregrino heavy-oil production while considering drainage strategy and well design. Recovery and production are maximized in Peregrino by extending the reservoir section length. As a result, every well in Peregrino is drilled with a long horizontal section inside the reservoir and completed with openhole gravel-pack lower completions. This strategy resulted in the longest wells in Brazil, with a record of 8613 m measured depth (MD) total length, with 2272 m MD in the horizontal section. To improve the effectiveness of sand control and avoid solids production, gravel is pumped to fill the annular space between the 8½-in. openhole section and the 5½-in.-outer-diameter screens. Inside the reservoir, water flows at a much higher velocity than viscous crude does. Therefore, inflow control devices are deployed in the lower completion to limit water flow into the wellbore at selected wells. To make gravel-pack operation feasible in such a configuration, sacrificial screens are installed in the bottom of the lower completion string. An artificial lift method is required to produce the heavy and viscous oil from the field and maintain commercial rates when pressure support and production declines. ESPs proved to be the most-efficient method for this application.

Formation interval determination method of MPD based on risk aversion and casing level optimization

MPD is one of the effective means to solve the drilling problems in deep-water and deep-stratum complex formations such as narrow pressure window. To reduce the cost, it is mostly implemented only in complex and narrow pressure window strata. However, at present, there is no scientific method to determine the MPD matching stratum interval under the “conventional + MPD” composite drilling mode. Aiming at this problem, by introducing the methods of risk quantitative evaluation and taking the principle of “avoiding risk and reducing MPD cost”, combined with the accurate ECD calculation method considering multiphase flow, this paper puts forward the accurate determination method of matching the stratum interval of MPD, which can reduce the section of MPD construction as much as possible and optimize the casing level on the premise of ensuring safety. Based on the artificial bee colony algorithm, the intelligent determination method of casing level and setting depth under the condition of pressure control is established, which can quickly and accurately obtain the maximum casing setting depth and its corresponding optimal pressure control parameters in the open-hole section. The case analysis shows that, compared with the conventional drilling mode, the “upper conventional + lower MPD” drilling method can save one layer of casing while ensuring safety. The proposed method can provide theoretical and scientific basis for the accurate calculation of MPD matching stratum interval under the “conventional + MPD” compound drilling mode and the scientific and efficient design of casing levels and setting depth under the condition of pressure control.

Solution and Analysis of Wellbore Temperature and Pressure Field Coupling Model under Lost Circulation.

The fluid in the annulus is in a variable mass flow state under the lost circulation condition, significantly affecting wellbore pressure distribution and the heat transfer efficiency between wellbore and formation. Therefore, based on the hydrodynamics and energy conservation law, a coupling model of transient wellbore temperature and pressure field under lost circulation conditions is established, which fully considers the casing program, bottom hole assembly, and heat source generated in drilling, as well as the influence of the temperature and pressure coupling in wellbore on the physical parameters of drilling fluid. The calculation results of the model in this paper are in good agreement with the field measured data and the previous research results, which verifies the rationality and accuracy of the model in this paper. The effects of the loss rate and the lost circulation zone location on the wellbore temperature and pressure distribution are analyzed, and the variation rule of the physical parameters of drilling fluid under the lost circulation condition is studied. The numerical simulation results show that the density and viscosity of drilling fluid in the annulus and bottom hole pressure increase with the increase in the circulation time; the annulus temperature decreases gradually with the increase in cycle time and tends to become stable after 8 h of the cycle. The annulus temperature and bottom hole pressure decrease with the increase in loss rate and closeness of the loss zone to the well bottom. When the loss zone is in the upper open-hole section, an inflection point consistent with the location of the loss zone appears on the annular temperature difference curve between the loss circulation and the nonloss circulation, and the position of the loss zone can be judged according to the inflection point.