An Intelligent Completion and Artificial Lift Technology to Develop Large Carbonate Reservoirs: Novel Completion and Zonal Water Injection via Remote Control Methods to Develop Horizontal Wells

2021 ◽  
Author(s):  
Jin Fu ◽  
Xi Wang ◽  
Guobin Yang ◽  
Shunyuan Zhang ◽  
Chen Chen ◽  
...  
Keyword(s):  
Remote Control ◽  
Data Collection ◽  
Water Adsorption ◽  
Water Injection ◽  
Horizontal Wells ◽  
Carbonate Reservoirs ◽  
Control Methods ◽  
Vertical Wells ◽  
Horizontal Drilling ◽  
Artificial Lift

Abstract There are several large carbonate reservoirs that have drawn great attention of researchers in recent years. After optimization of drilling technologies, how to deploy artificial lift technologies to develop them more efficiently is another concern. Conventional zonal water injection technologies require repetitive operation with wirelines and cables, causing extensive tests and low efficiency. However, an intelligent zonal water injection string consisting of several preset cable packers, water injection pressure gauges, formation pressure gauges and downhole flow meters has simply optimized water injection parameters and efficiently developed all reservoirs in some China's mature oilfields, especially when the string is integrated with remote monitoring and control methodologies. With the rapid development of horizontal drilling and extended reach well drilling technologies, borehole conditions are becoming more and more complicated, which has brought more challenges to water adsorption testing of horizontal intervals and deployment of zonal water injection instruments. Compared with vertical wells, the water adsorption test and string running are more challenging for horizontal wells, in which we are faced by many a problem during zonal water injection, such as competitive slack off and tight pull, excessive or inadequate water injection, complicated operation process. Besides, well deviation, dog leg and horizontal section length shall be all taken into consideration during zonal water injection for horizontal wells. Therefore, novel strings and tools should be deployed. Now tight pull, slack off and long operation periods are common problems during zonal water injection of horizontal intervals. After dedicated research, a set of wireless intelligent water injection strings for horizontal wells has been invented. Based on pressure pulse water distribution technique, the water injection string is eligible for 32-stage adjustment, so one strip may accomplish testing, adjusting, injection, measurement and downhole data collection, in addition to automatic error correction during water injection. The field trial shows that this novel string may be tripped in and out smoothly, packers are set securely and released easily, in order to adjust opening of each water injection nozzle in the ground, with an error of no more than ±10%. Therefore, the novel completion and water zonal water injection string is capable of injecting water precisely via remote control methods. The wireless intelligent water injection string for horizontal wells that combines testing, adjusting, injection, measuring and data collection in one trip provides us with many downhole data, such as pressure, flow rate, temperature and so on. Therefore, water injection volume for each zone is monitored and controlled down hole. This technology is applicable for both horizontal and vertical wells that require zonal water injection.

Paleostructural control of hydrocarbon production from the Cretaceous Niobrara in a part of the Denver-Julesburg Basin of Colorado and Wyoming

2017 ◽  
Vol 54 (1) ◽  
pp. 33-48
Author(s):  
Tom Spurr ◽  
Jeff Ware
Keyword(s):  
Horizontal Wells ◽  
Niobrara Formation ◽  
Vertical Wells ◽  
Hydrocarbon Production ◽  
Horizontal Drilling ◽  
Water Currents ◽  
The Past ◽  
Bottom Hole ◽  
Porosity And Permeability ◽  
Reservoir Porosity

Horizontal drilling and fracture stimulation of the Niobrara Formation chalks within the last decade have resulted in a widespread resource play in the Denver-Julesburg (DJ) Basin where over 50,000 vertical wells had already penetrated the Niobrara. The first fracture-stimulated horizontal Niobrara well in the DJ Basin was drilled in 2005. By the end of 2015, over 2000 horizontal wells had been drilled targeting the Niobrara and these new wells have made over 120 MMBO and nearly 500 BCF. Thickness changes correlate with the varying success of hydrocarbon production from the Niobrara in a part of the DJ Basin of Colorado. In the study area, the Niobrara comprises four chalks with interbedded marlstones; from top to bottom the A, B, and C chalks, and the Fort Hays Limestone. The Niobrara B chalk is the primary target for horizontal drilling; both the A and C chalk are secondary targets. The Niobrara Formation is self-sourcing and the hydrocarbons in the study area are not thought to have migrated. Within the study area, productivity in the Niobrara may be directly related to thermal maturity. Regionally thinner Niobrara trends are more likely to contain more productive wells than where thicker Niobrara is present. Thin intervals also coincide with higher resistivity values in the Niobrara B chalk and higher bottom hole temperatures. Temperatures were likely elevated in these locations in the past which led to increased organic maturity. Reservoir porosity and permeability may be enhanced along thin trends where shallow water currents winnowed sediments. Mapping the interplay of thickness, resistivity, and temperature of the Niobrara Formation can greatly improve the success rate of drilling in this play.

scholarly journals Injection-production optimization of carbonate reservoir based on an inter-well connectivity model

2021 ◽  
pp. 014459872199465
Author(s):  
Yuhui Zhou ◽  
Sheng Lei ◽  
Xuebiao Du ◽  
Shichang Ju ◽  
Wei Li
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Production Optimization ◽  
Oil Field ◽  
Carbonate Reservoirs ◽  
Utilization Rate ◽  
Production Volume ◽  
Connectivity Model

Carbonate reservoirs are highly heterogeneous. During waterflooding stage, the channeling phenomenon of displacing fluid in high-permeability layers easily leads to early water breakthrough and high water-cut with low recovery rate. To quantitatively characterize the inter-well connectivity parameters (including conductivity and connected volume), we developed an inter-well connectivity model based on the principle of inter-well connectivity and the geological data and development performance of carbonate reservoirs. Thus, the planar water injection allocation factors and water injection utilization rate of different layers can be obtained. In addition, when the proposed model is integrated with automatic history matching method and production optimization algorithm, the real-time oil and water production can be optimized and predicted. Field application demonstrates that adjusting injection parameters based on the model outputs results in a 1.5% increase in annual oil production, which offers significant guidance for the efficient development of similar oil reservoirs. In this study, the connectivity method was applied to multi-layer real reservoirs for the first time, and the injection and production volume of injection-production wells were repeatedly updated based on multiple iterations of water injection efficiency. The correctness of the method was verified by conceptual calculations and then applied to real reservoirs. So that the oil field can increase production in a short time, and has good application value.

An Integrated Geologic and Engineering Assessment of Fracture-Flow Potential in the Ratawi Reservoir of the Wafra Field, Partitioned Neutral Zone

2008 ◽  
Vol 11 (06) ◽  
pp. 1071-1081 ◽  
Author(s):  
Amy Whitaker ◽  
C. Shah Kabir ◽  
Wayne Narr
Keyword(s):  
Transient Analysis ◽  
Water Injection ◽  
Flow Simulation ◽  
Simulation Models ◽  
Dual Porosity ◽  
Fracture Flow ◽  
Fractured Reservoir ◽  
Horizontal Drilling ◽  
Rate Transient Analysis ◽  
Production Characteristics

Summary The extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined the Wafra Ratawi grainstone for which production extending for 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity, and overall effect have been elusive. In this study, we find that a limited number of total fractures affect production characteristics of the Ratawi reservoir. Although fractures occur throughout the Wafra field, fracture-influenced reservoir behavior is confined to the periphery of the field where the matrix permeability is low. This work suggests that for the largest part of the field, explicit fractures are not necessary in the next-generation Earth and flow-simulation models. The geologic fracture assessment included seismic fault mapping and fracture interpretation of image logs and cores. Fracture trends are in the northeast and southwest quadrants, and fractures are mineralized toward the south and west of the field. Pressure-falloff tests on some peripheral injectors indicate partial barriers, and most of these wells lie on seismic-scale faults in the reservoir, suggesting partial sealing. A few wells show fractured-reservoir production characteristics, and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, however, to attest to the notion of localized fracture response. The spatially restricted fracture-flow characteristics appear to correlate with fracture or vug zones in a low-permeability reservoir. Presence of fracture-flow behavior was tested by constructing the so-called flow-capacity index (FCI), the ratio of khwell (well test-derived value) to khmatrix (core-derived property). Data from 80 wells showed khmatrix to be consistently higher than khwell, a relationship that suggests insignificant fracture production in these wells. Introduction The Wafra field is in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, as shown in Fig. 1. The field has been producing since the 1950s and has seen renewed drilling activity since the late 1990s, including horizontal drilling and implementation of peripheral water injection (Davis and Habib 1999). The Lower Cretaceous Ratawi formation contains the most reserves of the producing intervals at Wafra. The Ratawi oolite (a misnomer--it is a grainstone) reservoir has variable porosity (5 to 35%) and permeability that ranges from tens to hundreds of md (Longacre and Ginger 1988). The main Wafra structure is a gentle (i.e., interlimb angle >170°), doubly plunging anticline trending north-northwest to south-southeast, which culminates near its northern end. The East Wafra spur is a north-trending branch that extends from the center of the main Wafra structure. As seen in Fig. 1, relief on the Main Wafra structure exceeds that on East Wafra. The Ratawi oolite in the Wafra field has been studied at length, and various authors have reported geologic and engineering elements, leading to reservoir characterization and understanding of reservoir performance. Geologic studies are those of Waite et al. (2000) and Sibley et al. (1997). In contrast, Davis and Habib (1999) presented implementation of peripheral water injection, whereas Chawathé et al. (2006) discussed realignment of injection pattern owing to lack of pressure support in the reservoir interior. Previous studies considered the reservoir to behave like a single-porosity system. But recent image-log fracture interpretations indicate high fracture densities, suggesting that the implementation of a dual-porosity model may be necessary because the high impact of fractures during field development has been recognized in some Middle East reservoirs for more than 50 years (Daniel 1954). Static and dynamic data are required to characterize fracture reservoir behavior accurately (Narr et al. 2006). Geologic description of the fracture system, by use of cores, borehole images, seismic data, and well logs, does not in itself determine whether fractures affect reservoir behavior. While seismic and some image logs were available to locate fractures in the Wafra Ratawi reservoir, no dynamic testing with the specific objective of understanding fracture impact has occurred. So, to determine whether fractures influence oil productivity significantly, we used diagnostic analyses of production data and well tests of available injectors. The assessment of fracture effects in the Ratawi reservoir will be used to guide the next generation of geologic and flow-simulation models. Dynamic data involving pressure and rate have the potential to reveal the influence of open fractures in production performance. Unfortunately, pressure-transient testing on single wells does not always provide conclusive evidence about the presence of fractures with the characteristic dual-porosity dip on the pressure-derivative signature (Bourdet et al. 1989). That is because a correct mixture of matrix/fracture storativity must be present for the characteristic signature to appear (Serra et al. 1983). In practice, interference testing (Beliveau 1989) between wells appears to provide more-definitive clues about interwell connectivity, leading to inference about fractures. In contrast to pressure-transient testing, rate-transient analysis offers the potential to provide the same information without dedicated testing. In this field, all wells are currently on submersible pumps. Consequently, the pump-intake pressure and measured rate provided the necessary data for pressure/rate convolution or rate-transient analysis. We provide the Ratawi-reservoir case study primarily as an example of the integration of diverse geologic and engineering data to develop an assessment of fracture influence on reservoir behavior. It illustrates the use of production-data diagnostic tests to determine fracture influence in the absence of targeted fracture-analysis testing. The workflow can be applied to similar static/dynamic problems, such as fault-transmissivity determination. Secondly, this analysis illustrates the process of deciding that fractures, although present throughout the reservoir, may not lead to widespread fractured-reservoir characteristics (e.g., Allan and Sun 2003).

Improving Proppant Placement Success in Horizontal Wells in Layered Reservoirs in the Sultanate of Oman

2021 ◽  
Author(s):  
Andrew Boucher ◽  
Josef Shaoul ◽  
Inna Tkachuk ◽  
Mohammed Rashdi ◽  
Khalfan Bahri ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Complex Geometry ◽  
Horizontal Wells ◽  
Vertical Position ◽  
Sultanate Of Oman ◽  
Vertical Wells ◽  
Multiple Fractures ◽  
Initiation Point ◽  
Interval Selection ◽  
Geological Units

Abstract A gas condensate field in the Sultanate of Oman has been developed since 1999 with vertical wells, with multiple fractures targeting different geological units. There were always issues with premature screenouts, especially when 16/30 or 12/20 proppant were used. The problems placing proppant were mainly in the upper two units, which have the lowest permeability and the most heterogeneous lithology, with alternating sand and shaly layers between the thick competent heterolith layers. Since 2015, a horizontal well pilot has been under way to determine if horizontal wells could be used for infill drilling, focusing on the least depleted units at the top of the reservoir. The horizontal wells have been plagued with problems of high fracturing pressures, low injectivity and premature screenouts. This paper describes a comprehensive analysis performed to understand the reasons for these difficulties and to determine how to improve the perforation interval selection criteria and treatment approach to minimize these problems in future horizontal wells. The method for improving the success rate of propped fracturing was based on analyzing all treatments performed in the first seven horizontal wells, and categorizing their proppant placement behavior into one of three categories (easy, difficult, impossible) based on injectivity, net pressure trend, proppant pumped and screenout occurrence. The stages in all three categories were then compared with relevant parameters, until a relationship was found that could explain both the successful and unsuccessful treatments. Treatments from offset vertical wells performed in the same geological units were re-analyzed, and used to better understand the behavior seen in the horizontal wells. The first observation was that proppant placement challenges and associated fracturing behavior were also seen in vertical wells in the two uppermost units, although to a much lesser extent. A strong correlation was found in the horizontal well fractures between the problems and the location of the perforated interval vertically within this heterogeneous reservoir. In order to place proppant successfully, it was necessary to initiate the fracture in a clean sand layer with sufficient vertical distance (TVT) to the heterolith (barrier) layers above and below the initiation point. The thickness of the heterolith layers was also important. Without sufficient "room" to grow vertically from where it initiates, the fracture appears to generate complex geometry, including horizontal fracture components that result in high fracturing pressures, large tortuosity friction, limited height growth and even poroelastic stress increase. This study has resulted in a better understanding of mechanisms that can make hydraulic fracturing more difficult in a horizontal well than a vertical well in a laminated heterogeneous low permeability reservoir. The guidelines given on how to select perforated intervals based on vertical position in the reservoir, rather than their position along the horizontal well, is a different approach than what is commonly used for horizontal well perforation interval selection.

scholarly journals Mathematical description of a bounded oil reservoir with a horizontal well

2021 ◽  
Vol 2 (1) ◽  
pp. 67-76
Author(s):  
T. N. Nzomo ◽  
S. E Adewole ◽  
K. O Awuor ◽  
D. O. Oyoo
Keyword(s):  
Pressure Distribution ◽  
Effective Permeability ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Oil Reservoir ◽  
Vertical Wells ◽  
Anisotropic Permeability ◽  
Time Approximation ◽  
Reservoir Geometry ◽  
Short Time

Horizontal wells are more productive compared to vertical wells if their performance is optimized. For a completely bounded oil reservoir, immediately the well is put into production, the boundaries of the oil reservoir have no effect on the flow. The pressure distribution thus can be approximated with this into consideration. When the flow reaches either the vertical or the horizontal boundaries of the reservoir, the effect of the boundaries can be factored into the pressure distribution approximation. In this paper we consider the above cases and present a detailed mathematical model that can be used for short time approximation of the pressure distribution for a horizontal well with sealed boundaries. The models are developed using appropriate Green’s and source functions. In all the models developed the effect of the oil reservoir boundaries as well as the oil reservoir parameters determine the flow period experienced. In particular, the effective permeability relative to horizontal anisotropic permeability, the width and length of the reservoir influence the pressure response. The models developed can be used to approximate and analyze the pressure distribution for horizontal wells during a short time of production. The models presented show that the dimensionless pressure distribution is affected by the oil reservoir geometry and the respective directional permeabilities.

Water-assisted Flow of Heavy Oil in a Vertical Pipe: Pilot-scale Experiments

2012 ◽  
Vol 10 (1) ◽  
Author(s):  
Antonio C. Bannwart ◽  
Oscar M. H. Rodriguez ◽  
Jorge L. Biazussi ◽  
Fabio N. Martins ◽  
Marcelo F. Selli ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Annular Flow ◽  
Water Injection ◽  
Pilot Scale ◽  
Heavy Oils ◽  
Monitoring And Control ◽  
Two Phase ◽  
The Core ◽  
Artificial Lift ◽  
The Individual

The use of the core-annular flow pattern, where a thin fluid surrounds a very viscous one, has been suggested as an attractive artificial-lift method for heavy oils in the current Brazilian ultra-deepwater production scenario. This paper reports the pressure drop measurements and the core-annular flow observed in a 2 7/8-inch and 300 meter deep pilot-scale well conveying a mixture of heavy crude oil (2000 mPa.s and 950 kg/m3 at 35 C) and water at several combinations of the individual flow rates. The two-phase pressure drop data are compared with those of single-phase oil flow to assess the gains due to water injection. Another issue is the handling of the core-annular flow once it has been established. High-frequency pressure-gradient signals were collected and a treatment based on the Gabor transform together with neural networks is proposed as a promising solution for monitoring and control. The preliminary results are encouraging. The pilot-scale tests, including long-term experiments, were conducted in order to investigate the applicability of using water to transport heavy oils in actual wells. It represents an important step towards the full scale application of the proposed artificial-lift technology. The registered improvements in terms of oil production rate and pressure drop reductions are remarkable.

Geomechanical Approach in Classification of Borehole Failures in Fractured Carbonates of Boca De Jaruco Field

2021 ◽  
Author(s):  
Anna Vladimirovna Norkina ◽  
Iaroslav Olegovich Simakov ◽  
Yuriy Anatoljevich Petrakov ◽  
Alexey Evgenjevich Sobolev ◽  
Oleg Vladimirovich Petrashov ◽  
...  
Keyword(s):  
Stress State ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
In Situ Stress ◽  
Vertical Wells ◽  
Stress Regime ◽  
Geophysical Information ◽  
The Republic ◽  
Maximum Horizontal Stress

Abstract This article is a continuation of the work on geomechanically calculations for optimizing the drilling of horizontal wells into the productive reservoir M at the Boca de Haruco field of the Republic of Cuba, presented in the article SPE-196897. As part of the work, an assessment of the stress state and direction was carried out using geological and geophysical information, an analysis of the pressure behavior during steam injections, cross-dipole acoustics, as well as oriented caliper data in vertical wells. After the completion of the first part of the work, the first horizontal wells were successfully drilled into the M formation. According to the recommendations, additional studies were carried out: core sampling and recording of micro-imager logging in the deviated sections. Presence of wellbore failures at the inclined sections allowed to use the method of inverse in-situ stress modeling based on image logs interpretation. The classification of wellbore failures by micro-imager logging: natural origin and violations of technogenic genesis is carried out. The type of breakout is defined. The result of the work was the determination of the stress state and horizontal stresses direction. In addition, the article is supplemented with the calculation of the maximum horizontal stress through the stress regime identifier factor.

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