Openhole Completions Research Articles

Analysis of thermal production effect of multi-horizontal U-shaped well

The multi-horizontal section hot dry rock (HDR) heat extraction system is proposed for efficient deep geothermal resources mining in this study. The thermal-hydraulic numerical model of the multi-horizontal section geothermal exploitation system is set up, the space-time evolution of temperature field is analyzed. The sensitivity factors including completion schemes, horizontal well diameter, quantity of horizontal sections and spacing of horizontal sections are investigated. The simulation results show that the production temperature and heating power of the multi-horizontal HDR production system decrease with the development of mining, and the decreasing speed gradually slows down. The open hole completion can be preferred when the formation conditions permit. The variation of horizontal well diameter has little effect on heat production when other conditions remain unchanged. The quantity of horizontal sections to be 3 or 4 for better heat extraction performance under the spacing of horizontal section remains 300m and the spacing of the horizontal section to be 150m is recommended within the scoped of this study. The results of this study can provide guidance for HDR mining research.

A coupled three-dimensional wormhole modeling in heterogenous carbonate lithology in limited-entry and openhole completions

Wormhole propagation in carbonate formation is a well-researched area with several proposed empirical, analytical, and numerical models to predict the process efficiency. The most reliable and up-to-date model is the two-scale continuum (TSC) model, based on numerical simulation of reactive transport in a porous medium. The model has been utilized in two and occasionally in three-dimensional space but has yet to consider the lithology impact in three-dimensional space (3D). This study demonstrated the impact of lithology considering both openhole and limited-entry completion in 3D space. Moreover, the model considered the acid temperature impact on acidizing efficiency. Results showed that limited entry results in a longer wormhole at the expense of its coverage along the wellbore. Similarly, the higher the number of perforations, the lower the wormhole radius but the higher the coverage. Increasing acid temperature results in better dolomite and lower limestone acid stimulation efficiency. In mixed mineralogy, the positive impact of temperature appears at 50 °C and higher. Wormholes propagate in the limestone sections in layered formation with openhole completion, leaving the dolomite under-stimulated, even at high acid temperatures. Limited entry completion in dolomite layers did not prevent the acid from traveling to the limestone layers but provided limited stimulation in the dolomite section. This is the first study to utilize the TSC model to predict the acid stimulation outcomes at field conditions in 3D space.

Experimental study and prediction method of solid destabilization and production in deep carbonate reservoir during mining

Wellbore instability is one of the significant challenges in the drilling engineering and during the development of carbonate reservoirs, especially with open-hole completion. The problems of wellbore instability such as downhole collapse and silt deposit in the fractured carbonate reservoir of Tarim Basin (Ordovician) are severe. Solid destabilization and production (SDP) was proposed to describe this engineering problem of carbonate reservoirs. To clarify the mechanism and mitigate potential borehole instability problems, we conducted particle size distribution (PSD) analysis, X-ray diffraction (XRD) analysis, triaxial compression tests, and micro-scale sand production tests based on data analysis. We found that the rock fragments and silt in the wellbore came from two sources: one from the wellbore collapse in the upper unplugged layers and the other from the production of sand particles carried by the fluid in the productive layers. Based on the experimental study, a novel method combining a geomechanical model and microscopic sand production model was proposed to predict wellbore instability and analyze its influencing factors. The critical condition and failure zone predicted by the prediction model fit well with the field observations. According to the prediction results, the management and prevention measures of wellbore instability in carbonate reservoirs were proposed. It is suggested to optimize the well track in new drilling wells while upgrading the production system in old wells. This study is of great guiding significance for the optimization of carbonate solid control and it improves the understanding of the sand production problems in carbonate reservoirs.

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.

Impact of well completion types on oil drainage area in reservoirs

Well completion design plays a crucial role in oil production and reservoir management. This study examines the influence of various well completion types on the oil drainage area within reservoirs, with the goal of enhancing our understanding of how completion methods affect hydrocarbon recovery. Using advanced reservoir engineering techniques and simulations, this research investigates the dynamic interaction between well completion and the accessibility of oil resources. The study provides a comprehensive analysis of different well completion types, including open-hole completions, cased-hole completions, and multilateral completions, and evaluates their collective impact on the drainage area. It also explores the interplay between well completion strategies and reservoir properties, such as permeability, lithology, and fluid characteristics. The findings of this study reveal that the choice of well completion type can significantly influence the drainage area by affecting the flow paths and reservoir contact. Different completion methods can extend or limit the reach of hydrocarbon recovery, impacting oil production rates. The research underscores the importance of optimizing well completion design to maximize reservoir performance. Furthermore, the study addresses operational considerations related to well completion, including equipment selection, production optimization, and workover requirements. It offers insights into the economic and operational implications of different well completion strategies, providing valuable guidance for reservoir management. The outcomes of this research contribute to a deeper understanding of how well completion types impact the oil drainage area in reservoirs. This knowledge is valuable for reservoir engineers, operators, and industry professionals involved in oil production, assisting them in making informed decisions to optimize oil recovery, reservoir performance, and well completion strategies.

A Comprehensive Review of Screen Plugging during Openhole Sand Control Completions Installation: Causes, Consequences, and Best Practices

Summary In openhole completions, screens are one of the very common equipment used to control production of solids. Screens could get plugged during installation in case of improper wellbore fluid conditioning and displacement. Awareness of screen plugging is not widely spread, and many practicing engineers do not pay enough attention to its implications. In this paper, we discuss the causes, consequences, and ways of determining plugging and recommend best practices to reduce the risk of screen plugging. First, we review the various reasons for screens to get plugged during openhole completion installations and explain in detail undesirable events caused by screen plugging such as: Inability to properly displace wellbore fluids Inability to fully pack the screen annulus Damage to screens during displacement and gravel packing We also review downhole gauge data of several jobs to identify and discuss screen plugging signatures and their outcomes. Additionally, we discuss potential preventive measures. In openhole completions, it is very common to run screens in wellbores containing solids-laden fluids intentionally or unintentionally. Poor wellbore displacement or improper fluid conditioning can result in leaving some bigger size solids in the screen-running fluid (SRF), which could plug the screens. Also, the exposure of reactive shales to water-based fluids can destabilize the shales and lead to plugging. In some cases, the SRF quality control is not properly accounting for the actual flow inside the screen while running in hole, resulting in a false pass. We present several case histories of downhole gauge data analysis, showing evidence of screen plugging leading to excessive treating pressure, incomplete gravel pack, and, in a few cases, screen erosion during gravel pack operations. To prevent screen plugging, it is necessary to properly model all the displacement stages, pay attention to proper conditioning and quality control of the fluid, and ensure compatibility of the fluids with shales. A comprehensive review of screen plugging during sand control installation phase and its potential consequences supported with extensive downhole gauge data has not been published previously. This paper will be a valuable source of knowledge for completion engineers and help them better design and execute future operations.

Geoscience-engineering integration-based formation damage control drill-in fluid (GEI-FDC-DIF): An essential technology for successful extraction of deep mid-high permeability sandstone reservoirs

The impact of drilling-induced formation damage is often underestimated in deep mid-high permeability reservoirs, largely due to modest reductions in permeability reported by conventional evaluation methods. This study introduces an innovative geoscience-engineering integration-based formation damage control drill-in fluid (GEI-FDC-DIF) technology, specifically developed to mitigate the challenges posed by deep wells with open-hole completions. Utilizing comprehensive geological and engineering analyses, our methodology facilitates a multiscale space-time evaluation of formation damage, enabling precise quantification of its severity and evolution. Based on identified mechanisms, tailored GEI-FDC-DIF formulations and supporting process measures are developed to optimize formation damage control. Preliminary geological and engineering evaluations of the deep mid-high permeability sandstone reservoir highlight the acute risk of drilling-induced formation damage. Detailed quantitative analysis indicates fluid sensitivity and drill-in fluid induced permeability reductions ranging from 1.13% to 44.54% and 26.47%–65.55%, respectively, with absolute permeability declines extending into the hundreds of millidarcys. Invasion depths of drill-in fluids reach 3.9–56.6 m at 150 h and 7.6–92.6 m at 840 h, underscoring significant formation damage predominantly caused by solid plugging, fluid sensitivity, incompatibility, and oil phase permeability reduction. Incorporating a blend of acid-soluble fiber bridging, oil-soluble deformable temporary plugging agents, and liquid drainage enhancers, the GEI-FDC-DIF significantly improves plugging efficiency and filtrate flowback. The development and deployment of GEI-FDC-DIF have shown superior formation damage control capabilities, as corroborated by both laboratory and field applications, underscoring its promising potential for future use.

Hybrid Technology Incorporated Into Colombian Heavy Oil Field Development Plan

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213199, “Incorporating Hybrid Technology of CSS and Foam in Heavy Oil Field Development Plans: Practical Experiences and Lessons Learned,” by Romel A. Perez, SPE, Hector A. Rodriguez, and Jorge E. Romero, Ecopetrol, et al. The paper has not been peer reviewed. _ A research and development project was conducted to study the use of preformed foams to improve cyclic steam stimulation (CSS). The field results showed benefits in incremental oil production, improvements in energy efficiency, and reduction in carbon intensity. Based on those outcomes, and with the goal of extending the production life of mature assets, the hybrid technology of CSS plus foam improvements was incorporated into the heavy oil field development plans of the Middle Magdalena Valley (MMV) basin in Colombia. Pilot Results: 2019–2022 CSS maturity is one of the major challenges in the MMV. Many wells report more than 10 steam cycles, decreasing oil productivity, and a trend of shorter steam cycles (less than 10 months). Most injected steam drained the higher-flow-capacity intervals based on the permeability contrast within the pay zone and openhole completions. Therefore, the bullhead injection of preformed foam improvements implemented before the steam cycle was proposed as part of a conformance strategy. The main goal of the pilot test was to demonstrate the efficiency of the hybrid technology, extend the production life of steam cycles, increase oil recovery, and improve energy efficiency and carbon footprint. The CSS pilot was implemented in six wells of the Teca-Cocorna field (Fig. 1). Performance was evaluated in terms of incremental oil, carbon intensity, and energy efficiency. A similar approach was proposed to evaluate energy efficiency and greenhouse emissions of CSS and hybrid CSS based on numerical simulations and the performance of two wells in Block D-80 in China. By the end of this stage, an incremental oil of approximately 32,000 STB was confirmed. Only one well recorded almost 50% of the total incremental oil of the pilot, and one well was only evaluated for 6 months because of a mechanical failure. Incremental oil recoveries and geochemical analysis confirmed the potential of this hybrid steam method to target unswept zones in idle or marginal wells operating since the 1980s. Additionally, the Teca-Cocorna pilot reduced carbon intensity and improved energy efficiency by 56% and 54%, respectively. The reduction of the carbon intensity from 83 (baseline) to 46 kg CO2/STB represents an important achievement in terms of environmental benefits and highlights the fact that the volume of natural gas used to generate steam was optimized by using less gas by extending steam cycles to a minimum of 9 months. In other words, the CCS/foam cycle can produce as much oil as two CCS cycles in the pilot wells.

Experimental Investigation of Fracture Propagation in Clayey Silt Hydrate-Bearing Sediments

More than 90% of the natural gas hydrate resources are reserved as marine clayey silt sediments. It is of great significance to efficiently develop a clayey silt hydrate. At present, there are problems of low single well production and small depressurization range in its production test, which is still a long way from commercial exploitation. The combination of hydraulic fracturing technology and other methods such as depressurization method is regarded as one of the potential technical means to achieve the commercial exploitation of the hydrate. However, compared with shale gas reservoirs and coalbed methane reservoirs, clayey silt hydrate reservoirs have special mechanical properties, resulting in unique hydraulic fracturing processes. Therefore, it is necessary to study the fracture initiation and propagation laws of clayey silt hydrate reservoirs. To this end, we carried out large-scale (30 × 30 × 30 cm) true triaxial hydraulic fracturing experiments using a simulated material with similar mechanics, porosity, and permeability to clayey silt hydrate-bearing sediments. The effects of completion method, fracturing method, and fracturing fluid displacement on hydraulic fracture propagation of clayey silt hydrate-bearing sediments were studied. The results showed that a perforated completion can significantly increase the fracture reconstruction area and decrease the fracture initiation pressure compared to an open hole completion. Due to the small horizontal stress difference, it is feasible to carry out temporary plugging fracturing in clayey silt hydrate reservoirs. Temporary plugging fracturing can form steering fractures and significantly improve fracture complexity and fracture area. Increasing the fracturing fluid displacement can significantly increase the fracture area as well. When conducting fracturing in clayey silt hydrate-bearing sediments, the fracturing fluid filtration area is obviously larger than the fracture propagation area. Therefore, it is recommended to use a high-viscosity fracturing fluid to reduce the filtration of the fracturing fluid and improve the fracturing fluid efficiency. This study preliminarily explores the feasibility of temporary plugging fracturing in clayey silt hydrate reservoirs and analyzes the effect of completion methods on the propagation of fracturing fractures, which can provide a reference for the research conducted on the fracturing stimulation of clayey silt hydrate reservoirs.

Permeability anisotropy impact on wormhole propagation in openhole and limited-entry completions: A 3D numerical study

The permeability in carbonate reservoirs is not the same in all directions (i.e., anisotropic), a property seldom considered in acid stimulation. The study hypothesizes that permeability anisotropy impacts acid treatment efficiency significantly. The investigation included the openhole and limited-entry completions in a vertical and horizontal wellbores configuration. A model based on the two-scale continuum approach was constructed in three-dimensional space (3D), resembling the big block experiment with the wellbore at the center. Permeability anisotropy significantly impacts acid efficiency in terms of the pore volume to breakthrough (PVBT) and optimum injection rate. For instance, simulations of acid placement in an openhole horizontal well with 10 anisotropy ratio resulted in PVBT of 0.15 compared to 0.35 in a vertical well. Limited entry completions result in more extended wormholes where the permeability anisotropy positively impacted wormhole length as compared to isotropic permeability. Nevertheless, the permeability anisotropy negatively impacted wormhole coverage along the wellbore in most scenarios. The simulations showed that a spear-like wormhole propagates from a limited entry horizontal wellbore in anisotropic formation, which previous studies assumed to be spherical or ellipsoidal. This implies that the skin factors models should be revised based on the new findings. This is the first study to assess the permeability antitropy impact on the stimulation of openhole and perforated wells in a 3D space.

Prediction of Sanding Likelihood Intervals Using Different Approaches

Sand production is undesirable matters, occurring in wells that are producing from sand reservoirs. It causes many problems such as erosion and grains accumulation in downhole and surface equipment’s, and formation subsidence. Important stage in sanding problem solution is a prediction of likelihood sand production intervals. In present paper, a vertical well X1 that is producing from Asmari reservoir in Y field at southern Iraq was selected for study. Asmari reservoir was classified to six units: A, B1, B2, B3, B4, and C. B zones consisted from sandstone with others rock types. Eight approaches were used for prediction sanding onset intervals by dealing with X1 well as open hole completion. Utilized eight prediction methods are compressional sonic wave (CSW), unconfined compressive strength (UCS), total porosity (PHIT), shear modulus to bulk compressibility (G/Cb), B-Index, Schlumberger index (S- Index), combined index (Ec-Index) and critical drawdown pressure (CDDP). All these methods performed based on 2462 measured points of CSW, sonic shear wave log (SSW), and density log (DL). Sand production likelihood intervals was selected by determination of cutoff values of adopted methods. Sand is possible to occur if interval has values lower than cutoff values of G/Cb, UCS, B-Index, S-Index, Ec, and CDDP and greater than cutoff values of CSW, and PHIT. Obtained cutoff values of eight approaches were 800 x 109 psi2, 36 Mpa, 0.2, 80 us/ft, 10000 Mpa, 108 Mpa, and 2700 Mpa, of G/Cb, UCS, PHIT, CSW, B-Index, S-Index, and Ec respectively. As well as sand production is possible to occur of bottomhole flowing pressure lower than calculated CDDP. Some Intervals had high CDDP that referred to abnormal pressure zones consisted from shale. Determination of sand onset intervals is a key for selecting best methods for controlling.

A Productivity Prediction Model for Multistage Fractured Horizontal Wells in Shale Gas Reservoirs

The tiny sizes of pores and throats in shale gas reservoir increase the complexities of the flow mechanisms, which challenge the accuracy of current productivity models during optimization design and prediction for multistage fractured horizontal wells (MFHWs). This paper established a productivity prediction model for MFHWs with cased hole completion and open hole completion. The model couples the gas flow in the matrix, fractures, and wellbore using potential superposition principle and considers multiple mechanisms of gas flows in a shale gas reservoir, such as stress-sensitive effect, wellbore friction, as well as interference between fractures. Based on the developed model, a productivity prediction method for MFHWs in shale gas reservoirs has been established, and sensitivity of the impact factors on productivity was analyzed. The analysis revealed that MFHWs are suitable for shale gas reservoirs with certain thickness. The number of fractures has significant impact on the production of shale gas reservoir. And the fractures at the both sides have higher production rate than the intermediate ones for multistage fractured horizontal wells. The fracture half-length has insignificant effect on the productivity of MFHWs. The production of shale gas reservoir also increases with pressure drop. The wellbore friction has insignificant effect on the production of MFHWs. The findings of this study can provide a basis for scientific evaluation of the production of MFHWs in shale gas reservoirs.

Evaluating the screen performance in sand control design by laboratory sand retention test

To produce oil and gas from unconsolidated sandstone reservoirs, sand screens are necessary to control sand flowing from the formation into the wells, causing well pluggings. In open hole completion, stand-alone sand screen is an essential component to prevent sand production, thus, selection of suitable sand screens is critical to minimize sand production and optimize the well’s production life. 
 Nowadays, premium screens with steel meshes make the openings of the screen slots complex in shape, resulting in a very different effect of sand retention compared to the traditional screens. The sand retention test is considered a standard and must be conducted to select screen opening and size, which decides the sand prevention capacity of the screen. 
 The paper presents the factors affecting the results of laboratory sand retention tests and proposes solution in the direction of considering the data trend rather than relying completely on the output results. The paper also brings about the evaluation method through the change the screen’s permeability to have better qualitative results compared to the traditional methods.

Drilling and completion technologies of coalbed methane exploitation: an overview

Coalbed methane (CBM) drilling and completion technologies (DCTs) are significant basis for achieving efficient CBM exploration and exploitation. Characteristics of CBM reservoirs vary in different regions around the world, thereby, it is crucial to develop, select and apply the optimum DCTs for each different CBM reservoir. This paper firstly reviews the development history of CBM DCTs throughout worldwide and clarifies its overall development tendency. Secondly, different well types and its characteristics of CBM exploitation are summarized, and main application scopes of these well types are also discussed. Then, the key technologies of CBM drilling (directional drilling tools, measurement while drilling, geo-steering drilling, magnetic guidance drilling, underbalanced drilling and drilling fluids), and the key technologies of CBM completion (open-hole, cavity and under-ream completion, cased-hole completion, screen pipe completion and horizontal well completion) are summarized and analyzed, it is found that safe, economic and efficient development of CBM is inseparable from the support of advanced technologies. Finally, based on the current status of CBM development, the achievements, existing challenges and future prospects are summarized and discussed from the perspective of CBM DCTs.

Maximizing well productivity by using filter cake breaker for synthetic-based mud drill-in fluid (SBMDIF) system

• Formation damage has a significant impact on the overall performance. • An effective filter cake breaker selection is critical to minimize formation damage. • The straightforward reaction of meso‑surfactant and nano-surfactant filter cake breakers with barite. • Surfactant-based filter cake breaker was more efficient in removing synthetic-based drilling mud. Formation damage has a significant impact on the overall performance of the well productivity. Removal of filter cake which is deemed to be the main strategy of formation damage remediation is crucial in open hole completion with pre-slotted liner or stand-alone screen (SAS) as a mean of sand control. Without proper planning, inefficient filter cake removal can lead to tremendous consequences since filter cake can plug the sand control component. Making the condition worse, sand control component is susceptible to plugging. This highlights the importance of selecting an effective filter cake breaker that can successfully remove the filter cake through dissolution of the main solids that constitute the major portions of the filter cake which could be the weighting material, barite, or calcium carbonate. Besides that, a proper understanding of the mechanism of the filter cake breaker chemical would be very beneficial to comprehend the filter cake breaker efficiency. The laboratory study attempted to emulate the reservoir condition. Regained permeability testing using High Pressure High Temperature (HPHT) Filter Press aimed to test the ability of several commercial filter cake breakers in removing synthetic-based-mud drill-in-fluids (SBMDIF). Chelating-based filter cake breaker, meso‑surfactant-based filter cake breaker and nano-surfactant-based filter cake breaker were the samples to be tested in the laboratory work. The condition of the filter cake after being soaked statically was visually interpreted and the regain permeability was recorded. The mechanism of each filter cake breaker to remove the SBMDIF filter cake was also examined. Based on the experimental study, meso‑surfactant-based filter cake breaker was found to be more effective to remove SBMDIF filter cake compared to chelating-based filter cake breaker and nano-surfactant-based filter cake breaker.

Modelling the near-wellbore rock fracture tortuosity: Role of casing-cement-rock well system, perforation and in-situ stress

Near-wellbore rock fracture is a key subject in subsurface energy extraction. Casing perforation completion is perhaps the most used type of well design mainly in comparison to the open hole completion. However, the effects of the combined casing-cementing-rock structure on pressure transmission in fracturing the rock have not been sufficiently addressed, but is key to understanding some important phenomena in hydraulic fracturing, such as fracture tortuosity. Here we develop a combined analytical-numerical model to investigate the rock fracture mechanism near the wellbore with realistic consideration of the boundary condition imposed by the complete well system. Different well configurations can lead to variation in the pressure applied on the rock formation and hence affect the fracture propagation near the wellbore. Our results show, as the pressure transmission through the well structure is enhanced, the fracture propagates more closely to the perforation orientation with a smaller deflection angle and the breakdown pressure is increased. The near-well tortuosity of the crack can be reduced by decreasing the thickness of casing and cement sheath, reducing Young's modulus of casing and increasing Young's modulus of cement up to around 15 GPa, based on the realistic range of values of the well parameters. The effects of in-situ stress condition and perforation angle and length on the near-well cracking are also investigated. The developed model can be used to aid decision making in terms of improved understanding of hydraulic fracturing technology and well design optimization.

Experimental study on hydraulic fracture propagation behavior on dolomite rocks with open-hole completion

To determine to discuss fracture mechanisms and the possible encounter problems in open-hole fracturing in tight carbonation, tri-axial hydraulic fracturing experiments were performed on dolomites with acoustic emission monitoring. The results demonstrate that a complex fracture network is difficult to create in most cases even if the dolomite has high brittleness. In general, fractures likely have three types of fracture geometry, namely, bi-wing fractures, local multiple fractures and complex multiple fractures. However, even if multiple fractures can be initiated with open-hole completion, they still can finally merge into one dominant hydraulic fracture (HF). Branch fractures can be observed with low horizontal stress difference and low fluid viscosity. The breakdown pressure on dolomites has a positive relationship with the high fluid viscosity and fluid injection rate, but a negative relationship with the high horizontal principal stress difference. The existence of natural fractures and critical engineering parameter differences should simultaneously contribute to the ratio of branch fracture and diverge fracture. The microscopic observation results reveal that natural fractures that are infilled with mixed calcite minerals are more likely activated due to the lower strength of these minerals, and the main HF is arrested with a natural fracture that is infilled with high-strength calcite minerals. The separation of calcite clusters may exert competing effects on the fracture conductivity. On one hand, the debonded calcite clusters can seal and plug open HFs and reduce the fracture conductivity if the fracture width is not substantial. On the other hand, a calcite cluster can be a type of natural self-proppant to sustain long-term conductivity. The selection of open-hole completion in dolomite selection increases the risks of wellbore deformation but no serious wellbore collapse can be observed. Thus, hydraulic fracturing using open-hole completion can be recommended in dolomite reservoir development if the fracture height containment problem is not a critical issue.

Using Linear Flow Parameter Initial Rate Method to Optimize Completion Design of Western Canada’s Montney Tight Gas Reservoir

Since 2007, the horizontal well staged fracturing technology has been widely used in the development of tight sandstones in the Deep Basin Montney reservoir of Western Canada Basin. The horizontal length of the horizontal well, the amount of proppant added to the fracturing and completion, the frac stage spacing, and the choice of open-hole completion or casing completion have become important factors in the optimization of completion design. LFPIR (Linear Flow Parameter Initial Rate) is observed through the double logarithmic curve of the natural gas production data of the well. After the development enters the stable linear flow stage, the linear flow corresponding to the ideal situation can be obtained when the initial production rate in this stage is inversely extended to tD≈0. The LFPIR depends on the stimulated volume of the reservoir after fracturing, and the completion effect directly affects the size of the stimulated reservoir. The completion quality of the well can be judged by studying the LFPIR of the developed Montney horizon well in the Heritage area. By comparing the LFPIR of wells with different completion designs, optimize the completion design in the tight gas reservoirs.

Technology Focus: High-Pressure/High-Temperature (March 2022)

What a difference a year can make. Oil and gas prices have reached and stabilized at levels that have not been seen for over half a decade, demonstrating that the adage “low oil prices are the remedy of low oil prices” is still true. Let us now see if we are again at the cusp of a new period of exuberance and if the cyclical nature of oil prices could soon show its grim face once more. A key industry discipline required to delay, or maybe even avoid, another price collapse is the planning and execution of high-pressure/high-temperature (HP/HT) projects. Perhaps the movement of some financial institutions toward considering environmental, social, and governance aspects when deciding to fund oil and gas projects will provide the beneficial longer-term stabilization of the current oil and gas price levels. More than ever, the saying “the easy/cheap oil is over” is true, and that requires a more-stable economic environment than we had in past years to assure the world’s uninterrupted energy and chemical feedstock supply, an important share of which will come from HP/HT reservoirs. For this year, I think we can see where the activity currently is from the available HP/HT related papers of the past year or two. A predominance of papers came from Chinese companies enthusiastically embarking on these challenging projects to secure their domestic energy needs and reporting their technology innovations and learning curves in interesting case studies. I was able to find some geographic diversity by including case studies from the Middle East as well, where good ideas and innovative low-cost approaches have enabled economically feasible project delivery in tough times. Notably absent in the choice of papers were the traditional HP/HT areas of the deep Gulf of Mexico and the North Sea. But maybe the more favorable oil and gas prices will spawn some new activity in these areas as well, if the regulatory and fiscal environment also improves. Reading this year’s case studies, some of the more experienced engineers among us will notice that, on some occasions, known challenges have been encountered that, in our experience, had been successfully mitigated in previous projects. This is likely a weakness from the Great Crew Change, where the knowledge preservation and transfer may not always have happened satisfactorily. The cut-throat cost-saving environment of the past few years, combined with the worldwide health crisis leading to curtailed travel and many workshops and conferences being canceled, certainly contributed to this lack of information flow as well. This is why it is so important to engage in SPE through online interest/discussion groups to find the necessary expertise in our pool of members. With this recommendation, I hope you will read the 2022 featured papers with interest and take them as encouragement and a source of good ideas for the years of greatly improved activity levels before us. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 20148 - Solid Management Optimization for Offshore Big-Bore HP/HT Sour Gas Well Cleanup by Ardian Nengkoda, Saudi Aramco, et al. SPE 199052 - One of the Deepest Wells Drilled in Bolivia: High Pressure and Temperature in More Than 9 Months of Drilling, No Casing Wear Detected by Russell Mertens, WWT International, et al. SPE 202250 - Next-Generation Ceramic Sand Screens as Openhole Completion Solution in High-Rate Erosive and Corrosive Well Environment at Dvalin HP/HT Field, Offshore Norway by Robert Ritschel, Wintershall DEA, et al.

Numerical simulation of progressive sand production of open-hole completion borehole in heterogeneous igneous formation

Sand production can occur during hydrocarbon production, which poses a significant issue for continued oil and gas production. The existing finite element simulation of sand production usually assumes that the formation rock is a homogeneous medium. However, the actual formation is usually a heterogeneous natural material; during the testing and production process, sand production is a long-term, continuous, and gradual process. The wellbore pressure change has an important influence on sand production. Therefore, this study presents a numerical simulation method for progressive sand production in inhomogeneous formations. First, based on the theory of elastic damage mechanics, considering the heterogeneous characteristics of formation rock physical properties and mechanical parameters, a steady-state coupled hydraulic-mechanical-damage finite element model was established. Second, a multi-layer finite element method with multiple iterations was used to solve the model. After each iteration, the material mechanical parameters were updated to simulate the damage unit equivalent, which simulated the progressive sand production process. Finally, sand production during testing in typical igneous formations was analyzed, the influences of heterogeneity, progressive failure process, and wellbore pressure change are discussed in terms of progressive sand production, and systematic parametric simulation and analysis were conducted. The results show that the sand production zone is controlled by the formation rock heterogeneity and progressive failure process. The results indicate that the sensitivity of the normalized yield zone area (NYZA) to mean parameter value can be ranked as follows: cohesion > Poisson's ratio > Young's modulus > internal friction angle, and the sensitivity of the NYZA to standard of deviation parameter value can be ranked as follows: internal friction angle > Poisson's ratio > Young's modulus > cohesion.