Horizontal Completions Research Articles

Mechanical model and optimal design method of tubular strings with connectors constrained in extended-reach and horizontal wells

Mechanical analysis and optimal design of down-hole tubular strings with connectors are the key theoretical bases of design and operation in extended-reach and horizontal drilling and completion. However, the complex mechanical interaction between spring connectors and open wellbores are not fully considered in conventional tubular models and the conventional design methods are mostly based on experience and lack of rigorous mathematical derivations. To overcome these shortcomings, a new revised mechanical model and an optimal design method of connectors on down-hole tubular strings have been built. Firstly, the local loads on a unified connector which can depict common spring and rigid connectors constrained in open wellbores are studied. The local connector loads are further introduced into the local mechanical model of tubular strings. The integral mechanical model of tubular strings is amended by the local model. Next, the integral design model of connectors while considering friction reduction, tubular centricity and cost is built. The integral design model is divided into a series of local design models according to the properties of tubular mechanical behaviors on extended-reach and horizontal wellbores. At last, the mechanical model and design method are applied to drill strings with joints and casing strings with centralizers in horizontal drilling and completion.The results indicate that the revised tubular mechanical model and connector design model are stable and fast. The coupling effects of connector and buckling, local drags on connector and radial compression of spring connectors are all included in the mechanical model, so the new model gives a more sophisticated description of mechanical behaviors of tubular strings with connectors. The design results of anti-drag joints are closely related to the clean condition of wellbores. Proper optimal design of connectors and good clean condition of wellbores can inhibit helical buckling, decrease friction factor and reduce plough effect, leading to larger lateral extending limits. Compared with the initial design results of centralizers, friction force is decreased and casing centricity is increased through optimization design. The optimization results of centralizers are closely related to the weight values of friction reduction, casing centricity and cost. Therefore, the key problem is how to assign these three weight values under actual engineering conditions.

Mexican Unconventional Plays: Geoscience, Endowment, and Economic Considerations

Summary Successful activities in the Eagle Ford Shale in Texas through drilling of horizontal wells and completions by use of multistage-hydraulic-fracturing jobs suggest that the potential of shale reservoirs farther south will be quite significant. This observation leads to the objective of this paper: to examine geoscience and engineering data of tight and shale reservoirs in Mexico with a view to estimating the oil and gas endowment, and to determine the economics of developing these plays under current and forecast possible oil and gas prices. Plays considered in this study include the Burgos, Sabinas, Tampico, Tuxpan (Platform), Veracruz, and Chihuahua Basins. Endowment is defined by the US Geological Survey (USGS) (USGS 2000) as the sum of known volumes of oil and gas (cumulative production plus remaining reserves) and undiscovered volumes. The economics of these plays is examined with the use of cumulative long-run supply (or availability) curves. These are presented as crossplots of production costs per barrel of oil or per Mcf of gas vs. endowments for the aggregate of basins, and are very useful to demonstrate how endowment volumes vary at different price levels. It is concluded that the potential of unconventional resources in Mexico is quite significant and will help to change the slope of production rates in the country from negative to positive. As a result, it is anticipated that Mexico will become an important part of the shale-petroleum revolution started in the US.

A semi-analytical model for predicting screen-out in hydraulic fracturing horizontal wells

Proppant Screen-out has been generally recognized as an issue affecting the performance of hydraulic fracturing in horizontal well completion. There is lack of a method that can be used to predict the screen-out. This paper provides a semi-analytical model for describing the configuration of proppant pile in ideal fracture conditions and predicting the time at which the screen-out occurs during fracturing horizontal wells. Result of case study is consistent with field data with certain error. Sensitivity analyses with this semi-analytical model indicate that optimizing fluid viscosity, injection rate, proppant density, proppant size, distribution of proppant size and the ratio of proppant volume to fracturing fluid volume can eliminate or at least delay the occurrence of screen-out. This semi-analytical model provides engineers a method for optimizing fracturing parameters to minimize the detrimental effect of screen-out to horizontal well performance.

Оценка эффективности применения технологий форсированного отбора жидкости и бурения боковых горизонтальных стволов на залежах с высоковязкой нефтью

Оценка эффективности применения технологий форсированного отбора жидкости и бурения боковых горизонтальных стволов на залежах с высоковязкой нефтью

Impacts of Bakken Shale Oil Development on Regional Water Uses and Supply

AbstractThe Bakken shale play in western North Dakota is one of the largest unconventional oilfields in the United States, but published research about impacts on the region's water resources is rare. In this study, besides examining North Dakota water management policies and activities, we also analyzed three datasets: the Bakken horizontal well completion data (2008‐2014), North Dakota permitted water consumption data (2000‐2014), and groundwater level and streamflow observations in western North Dakota (2000‐2014). We found from 2008 to 2014, the annual total industrial water uses for Bakken shale oil development ranged between 0.5 and 10% of statewide total consumptive water use. The percentage increases were between 3.0 and 40% within the Bakken oil production region. The increased population of temporary oilfield service workers contributed additional domestic water use, which was equivalent to ~15% of annual industrial water use for the shale oil development in the Bakken. Despite being in a semiarid region, the impact of Bakken development on regional water supply was limited because the water in the Bakken was adaptively managed and the region received on average over 20% more precipitation than normal during 2008‐2014. Of the 15 glaciofluvial aquifers under study, 12 have seen water levels increasing or unchanged and the water levels for the remaining 3 aquifers have decreased.

Technology Focus: New-Frontier Reservoirs II (October 2017)

Technology Focus A year ago, this feature noted the continued languishing of crude-oil prices and the low margins in tight and very tight reservoir asset developments and the resulting substantial reduction in new-well drilling and completion. Little has changed since then. In the meantime, technology advancements have enabled a greater number of hydraulic fractures in long horizontal completions in such reservoirs, for example, resulting in more-cost-effective completions and greater initial oil-production rates. But low primary oil recovery and steep initial-production-rate declines still present overriding limitations. These tight and very tight oil-bearing reservoirs are typically characterized by oil-recovery factors of approximately 10%. However, on a positive note, in addition to improvements in completion efficiencies, recent advancements also have been made in the understanding and application of enhanced-oil-recovery (EOR) methods in such reservoirs. While enhancing oil production from multizone, hydraulically fractured completions in tight reservoirs is not straight forward, recent studies, including field trial programs, have shown that applications such as gas injection and waterflooding, including smart water injection, have the potential to create significant improvement in oil recovery. The three papers featured this month are from Canada. All address the importance of wettability and wettability alteration in improving sweep efficiency and oil extraction by use of gas injection or water injection. Both laboratory studies and field application, in the case of waterflooding, are discussed. Each, with their unique perspectives and approaches, provides understanding of EOR fluids; formation interactions; and the benefits and present limitations of gas injection, conventional waterflooding, and smart water injection. Recommended additional reading at OnePetro: www.onepetro.org. SPE 185037 EOR in Tight Reservoirs—Technical and Economic Feasibility by K. Joslin, Computer Modelling Group, et al. SPE 185680 Compositional-Simulation Evaluation of Miscible-Gas-Injection Performance in Tight Oil Formation by Ahmed Mansour, Texas Tech University, et al. SPE 180284 The Use of Propellants To Stimulate and Enhance Productivity From Tight, Damaged, and Low-Quality Reservoirs by J. Gilliat, Baker Hughes, et al.

ANALYSIS OF QUALITY OF PERFORATION OF PRODUCTION FORMATIONS BY WELLS WITH HORIZONTAL COMPLETION

The paper presents correlation-regression analysis of the influence of various factors on the oil production rate of wells with horizontal completion. Attempt was taken to create a model of multiple correlation for explaining the combined effect of these factors on production rate. The model allows both predicting with sufficient accuracy rate the production rate of the well based on drilling and completion data with a sufficiently high proportion of accuracy, and ranking various factors according to the degree of their influence on production rate.

RESULTS OF APPLYING THE METHODOLOGY FOR THE QUANTITATIVE ASSESSMENT CONFIRM THE PREDICTION OF THE 3D MODELFOR HORIZONTAL SECTION OF WELLS

The article discusses results of the use methodology for quantification of prediction of the 3D model for geosteering. This methodology tested for 90 wells with horizontal completion. According to the obtained statistics to assess factors affecting the reliability of the forecast model and defines the boundary criteria of quality confirmation.

Hydraulically Fractured Formations: Parameters Controlling Performance and Maximum Number of Fractures

Horizontal wells essentially increase the area of contact between wellbores and reservoir fluids to some extent. Hydraulic fractures increase this area significantly and develop the vertical permeability. Because of these two techniques, well deliverability or productivity index can be increased to the limit required by the worldwide needs. Several models have been derived for the productivity index of fractured formations and the maximum number of fractures for both finite and infinite reservoirs. The models were developed based on the idea that the total pressure drop in the wellbore can be estimated as the sum of different pressure drops caused by different flow regimes. This pressure drop is necessary for the fluid to flow from the reservoir toward the wellbore. It is well known that the developed flow regimes in the area around the horizontal wells or the hydraulic fractures are not the same as the flow regimes at far distance from wellbores, which is close to the outer boundaries. Therefore, four flow regimes were expected to develop in infinite acting reservoir: pseudo radial flow at the outer boundaries, elliptical flow in the area between wellbores and the regions close to the outer boundaries, formation linear flow in the area between fractures toward wellbores and fractures, and finally fractures linear flow, while pseudo-steady state flow was the expected flow regime for the case of limited reservoirs. Each one of these flow regimes contributes to the total pressure drop necessary for producing certain flow rate in addition to the pressure drop caused by the damage zones resulted from horizontal well drilling and completion, hydraulic fracturing process, and fluid flow chocking effect. In this study, the effects of the anisotropy, fracture dimensions, radius of drainage area, number of fractures and fracture conductivity on productivity index had been investigated. A novel approach for the maximum number of fractures necessary for a specific productivity index was introduced in this paper. The model had been examined for two field cases taken from literatures. The calculated flow rates by this model showed good agreement with the measured flow rates.

Laboratory research of fracture geometry in multistage HFF in triaxial state

Multistage hydraulic fracturing of formation (HFF) in wells with horizontal completion is an efficientmethod for intensifying oil extraction which, as a rule, is used to develop nontraditional collectors. It is assumed that the complicated character of HFF fractures significantly influences the fracture geometry in the rock matrix. Numerous theoretical models proposed to predict the fracture geometry and the character of interaction of mechanical stresses in the multistage HFF have not been proved experimentally. In this paper, we present the results of laboratory modeling of the multistage HFF performed on a contemporary laboratory-scale plant in the triaxial stress state by using a gel-solution as the HFF agent. As a result of the experiment, a fracturing pattern was formed in the cubic specimen of the model material. The laboratory results showed that a nearly plane fracture is formed at the firstHFF stage, while a concave fracture is formed at the second HFF stage. The interaction of the stress fields created by the two principal HFF fractures results in the growth of secondary fractures whose directions turned out to be parallel to the modeled well bore. But this stress interference leads to a decrease in the width of the second principal fracture. It is was discovered that the penny-shaped fracture model is more appropriate for predicting the geometry of HFF fractures in horizontal wells than the two-dimensional models of fracture propagation (PKN model, KGD model). A computational experiment based on the boundary element method was carried out to obtain the qualitative description of the multistage HFF processes. As a result, a mechanical model of fracture propagation was constructed,which was used to obtain the mechanical stress field (the stress contrast) and the fracture opening angle distribution over fracture length and fracture orientation direction. The conclusions made in the laboratory modeling of the multistage HFF technology agree well with the conclusions made in the computational experiment. Special attention must be paid to the design of the HFF stage spacing density in the implementation of the multistage HFF in wells with horizontal completion.

Performance of Horizontal Wells with Inflow Control Devices in Homogeneous Reservoirs with Bottom Water Drive

Horizontal well techniques play an important role in the development of unconventional oil and gas plays. A key challenge in horizontal well completions is that water cut will rise rapidly once water breakthrough without inflow control. Inflow control devices restrict flow by creating an additional drop in pressure to equal the drop in wellbore pressure in order to reduce water or gas coning. Once a control device is installed in the wellbore, it is almost impossible to adjust. As a result, it is extremely important to understand the oil–water pressure profile and the long-term behavior of well completions with ICDs. We use the theory of dynamic simulation-coupled well-reservoir flow to analyze the performance of horizontal well completions with and without ICDs using the multi-segment well model. This study proposes a new single-flow wellbore model and develops the model of oil–water flow in horizontal wellbore with influx. The performance of horizontal well completions with ICDs in reservoir with water drive is analyzed on the basis of the new coupled reservoir–wellbore model. Simulation results show that water breakthrough first occurs near the heel of the horizontal well due to the drop in pressure in the wellbore by the end of water-free production period in the homogeneous reservoirs. We also point out that completion with ICDs can optimize production in horizontal wells with long production sections, low drawdown pressure and high production rates. In these situations, the effects of a drop in oil–water two-phase pressure are significant.

E&P Notes (April 2017)

E&P Notes Artificial Intelligence Holds Promise for Seismic and Drilling Data Stephen Whitfield, Senior Staff Writer As the oil and gas industry forges a new landscape in the wake of the financial downturn, an expert argued that artificial intelligence (AI) technologies could potentially have a disruptive, valuable impact on operations in the near future. In a webinar hosted by SeeAlgo, an AI consulting firm, Adnan Siddiqui discussed the ways in which AI and machine learning can improve project efficiency. Siddiqui, a principal at SeeAlgo, examined AI technology’s potential roles in several facets of oil and gas operations including seismic interpretation and well control event prediction. Ignored Signal During Hydraulic Fracturing Offers Instant Feedback Trent Jacobs, JPT Digital Editor A Denver-based startup company is trying to fine-tune a technique that would give shale producers instant gratification by explaining one small aspect of the behavior of fracturing fluids during a horizontal well completion. The subject of this research is known as the water hammer effect and, though others have investigated, no one has yet made complete sense of it. Founded in 2014, the oil and gas analytics firm Well Data Labs recently completed a study that aimed to get closer to unraveling the mystery. Because the signature of the water hammer signal is determined by the makeup of the wellbore and near-wellbore fractures, the engineering team behind the research believes the raw data can be crunched into a report that describes the quality of a well’s connectivity with the producing reservoir. PDC Optimistic About Wattenberg, Delaware Assets Stephen Whitfield, Senior Staff Writer Since selling its assets in the Marcellus in 2014, PDC Energy has undergone a major strategic shift in its hydraulic fracturing operations, focusing primarily on its acreage in Colorado’s Wattenberg field while entering the Delaware Basin in west Texas. As the independent exploration and production company enters the third year of this new operational focus, its top executive said there is plenty of reason for optimism. Speaking at a luncheon co-hosted by the Independent Petroleum Association of America and the Texas Independent Producers and Royalty Owners Association, PDC President and Chief Executive Officer Bart Brookman gave an overview of recent developments at the company. Brookman described the Wattenberg as a highly productive region for PDC, and that the company hopes to increase efficiency in the operation of its 96,000 acres. PDC utilizes a near-even split of standard-, mid-, and extended-reach laterals in the Wattenberg. Brookman said the company plans to drill each new well with monobore technology, saving approximately 1 day in spud-to-release times. It also plans to move from a 4½-in. liner to a 5½-in. casing on its laterals, which will allow for larger completion volumes and higher completion rates. Independent Shale Producer is Driving Permian Well Improvements With Clean Sweeps Trent Jacobs, JPT Digital Editor Good housekeeping has proven to be a big difference-maker for Houston-based Callon Petroleum. The independent shale producer recently published a study showing how it developed a data-driven workflow to predict which wells will suffer the most screenouts, allowing them to build in time for a preventive completion practice known as a clean sweep. “It’s not a new concept. It’s not a fancy technology,” said Nancy Zakhour, a completions engineer with Callon who worked on the study. “It’s just us trying to better understand which differences made to our operations are impacting production and whether or not we can leverage that to our advantage.” The company attributes its approach to clean sweeps to better proppant placement and higher production. While supporting figures have not been disclosed, Zakhour emphasized, “We came to know that whatever we did with the sweep enhanced the wells’ productivity.” Her confidence in the effectiveness of the clean sweeps is partly backed by hydraulic fracturing models that indicated that the fracture designs themselves were not the chief driver of well performance. Run post-completion, Zakhour said the models showed how the clean sweeps were allowing otherwise inactive perforations to be successfully “pumped to completion” with a full dosage of sand.

Industry and Academia Continue Working on Big Ideas for Nanotechnology

The nanotechnologies enjoying commercial success in the oil field today are small in number, and for the most part, can be categorized as single-well applications. Examples include the dissolvable ball-drop systems used in horizontal well completions and the specialty additives operators are using to enhance drilling fluids. The next big leap for this area of emerging technology will be the development of nanoparticles that work on larger scales, either in production operations or for fluid treatment. Counted among the industry’s nanopioneers, Saudi Aramco is getting closer to the deployment of nanoparticles for a number of reservoir-wide applications. Others are working on creating nanoparticles that will improve the performance of waterflooding, and university researchers in Texas are developing a magnetic nanoparticle that aims to make offshore water treatment more efficient, and possibly more economic. These concepts were presented at SPE’s Annual Technology Conference and Exhibition held last year in Dubai. Taken together, they offer a small, yet compelling, sample of the ideas still working their way through the pipeline. Kirk Rainey, the vice president of A&I Ventures in Houston and a former chemical-enhanced oil recovery expert at Shell, has been involved with nanotechnology consortiums for more than 7 years. Speaking generally, he explained that the oil and gas industry is interested in nanoparticles partly because of the potential efficiencies they offer. It helps to think of nanoparticles from a chemical perspective; their collectively high-surface-area—typically where chemical reactions take place—means even relatively small volumes can make a big impact. “The negatives include the fact that in many cases engineering these nanoparticles, or nanostructures, can be very costly,” said Rainey. “And while it may be easy to do on a small scale, learning how to scale something up to the oil field is going to take a lot of effort, and the ability to do that is sometimes unknown.” That point about scale is very important, especially when discussing reservoir applications. Rainey emphasized that if large doses of nanoparticles are needed, then their cost must be relatively low to justify their use. He said the ability to strike such a balance will separate “laboratory curiosities” from viable commercial products.

Exploring the Beetaloo: will Australia's first viable shale play be sourced by billion year old gas?

Origin Energy completed exploration campaigns in 2015 and 2016 in the Beetaloo Sub-basin of the Greater McArthur Basin in the Northern Territory, drilling three vertical wells and one horizontal well. These wells have provided a wealth of technical data to assist in the characterisation of the primary source rock reservoirs or ‘shale gas’ plays in the Basin – the Velkerri Formation Play and the Kyalla Formation Play. In this paper we demonstrate the presence of thick, gas saturated and over-pressured source rocks across the sub-basin. In addition to the drilling campaign, the multi-stage hydraulic fracture stimulation of the Amungee NW-1H horizontal well was completed in 2016 – this operation was unique as it represents the first horizontal stimulation operation in the Beetaloo Sub-basin and the longest ‘plug and perf’ type horizontal completion in Australia. Data from the extended production test of the Amungee NW-1H are critical from a technical and, potentially, economic and political perspective. In addition to the technical work program, Origin has undertaken preliminary environmental baseline studies and substantial stakeholder engagement. Ensuring environmental baseline data are available is key to demonstrating that onshore gas developments can be undertaken without adverse environmental outcomes, and also for gaining social acceptance. However, data and facts alone are not sufficient to build community confidence. Origin has engaged extensively with pastoralists, local communities and Traditional Owners to build direct relationships and partnerships that encourage acceptance of the gas industry’s ability to coexist and deliver mutual benefits to the businesses and communities of the Barkly region and the Northern Territory more broadly.

Qualitative modeling of multi-stage fractured horizontal well productivity in shale gas reservoir

As an important unconventional gas resource, shale gas has become an important part of gas production in recent years with the advantage of horizontal well drilling and large-scale multi-stage hydraulic fracturing completion technologies. The shale gas reservoir numerical simulation advances were reviewed and a multi-stage fractured horizontal well numerical simulation was performed to qualitatively modeling the well productivity in over-pressured shale gas reservoir based on actual shale properties and well completion parameters. A single horizontal well model was established on the basis of dual-porosity model and logarithmically spaced grid refinement. A comprehensive comparison and analysis of the initial average gas production, daily gas production, cumulative gas production, adsorbed gas and free gas cumulative production were provided to investigate the influence of matrix permeability, SRV permeability, hydraulic fracture conductivity and half length, SRV size, bottomhole pressure on the well performance. The research shows that for the high matrix permeability (Km > 10−7 mD) and low SRV permeability (KSRV < 0.01 mD), the SRV permeability has a significant impact on the initial average gas production. For the high matrix permeability (Km > 10−7 mD) and medium SRV permeability (0.01 mD < KSRV < 0.5 mD), the initial average gas production is controlled by both the matrix and SRV permeability. For the high matrix permeability (Km > 10−7 mD) and high SRV permeability (KSRV > 0.5 mD), the initial average gas production is mainly controlled by the matrix permeability. When the matrix permeability is lower than 10−9 mD, the cumulative gas production is too low to be of economic interest. For the matrix permeability (10−9 mD < Km < 10−5 mD), the matrix permeability and SRV permeability are all important factors that influence the cumulative gas production. For the matrix permeability (Km > 10−5 mD), the matrix permeability has much more impact on cumulative gas production than that of SRV permeability. The daily gas production and cumulative gas production are independent of hydraulic fracture conductivity and half length. The initial gas production of multi-stage fractured horizontal well is also independent of SRV sizes. The SRV size mainly controls the gas production decline characteristic. With the increase of the SRV size, the daily gas production declines slowly. The SRV size determines the cumulative gas production directly. With the increase of the SRV size, the cumulative gas production increases linearly. The bottomhole pressure has a significant impact on cumulative gas production. With the decrease of the bottomhole pressure, the cumulative gas production of 20 years increases linearly.

An engineering solution for CO2 injection in saline aquifers

In this proposed CO2 injection system, brine is extracted from the target storage aquifer by means of a lateral horizontal completion located near the top of the formation. It should be noted that the brine is not lifted to the surface. An Electrical Submersible Pump (ESP) is used to extract the brine and boost its pressure, before it is mixed with CO2 that is injected down the vertical section of the well. The mixing takes place in the vertical section of the well below the upper lateral. The CO2–brine mix is then injected into the same formation through a lower lateral. A down-hole tool would be used to maximise agitation and contact area between CO2 and brine in the vertical mixing section of the well, which may be tens to hundreds of metres long, depending on the thickness of the formation.The advantages of this method are that there is little overall pressure increase, because CO2 is mixed with brine extracted from the formation, and also the extracted brine is already at high pressure when it is mixed with the CO2, greatly increasing the solubility of CO2 and reducing the volume of brine required. Energy is not expended lifting the brine to surface nor is there any concern about handling large volumes of acidic brine in the surface equipment. In this study, in addition to the concept of the down-hole mixing (DHM) method which is presented, the application of the DHM method in a hypothetical storage site (Lincolnshire—Smith et al., 2012) is also examined. The calculations are performed to identify the optimum rates of water extraction and injection of dissolved CO2 in brine.

The in situ stress determination from borehole image logs in the Kuqa Depression

The Kuqa Depression is located in the northern part of Tarim Basin and is adjacent to the southern Tianshan orogen, which is subject to strong tectonic compression since the Neogene period and is extremely active at present. The accurate determination of the in situ maximum horizontal stress (SHmax) is important for stress-related geo-hazards and reservoir-related issues, such as borehole stability, horizontal well design, completion, sanding and fracture conductivity in fractured reservoirs in the Kuqa Depression. A borehole image technique is an effective method for stress determination in oil fields and is abundantly measured in the Kuqa Depression, including in water-based and oil-based mud environments. Based on 1954.08 m drilling-induced fractures and 3576.04 m borehole breakouts derived from imaging logs in 72 gas wells, SHmax values were determined in different tectonic units in the Kuqa Depression. The in situ stress direction from the west to east section in the depression shows an approximately clockwise rotation from NW to NE trending, which is consistent with the results derived from focal mechanism solution. Both conventional logging and borehole breakout can be well used for stress magnitude determination, while breakout is more preferable. The calculation of stress magnitude infers that the present-day regional stress intensity may be decreasing to the southward direction in the Kuqa Depression.

A completion staging case study in the Barnett Shale using advanced LWD quadrapole sonic and borehole imaging

Horizontal completions within a complex oil condensate window of the Barnett Shale have proven challenging because of problematic well placement within an optimum reservoir section and the vertical and mechanical proximity to mobile water in the Viola Limestone. Accurate formation properties along the horizontal well are required to identify both conditions in order to effectively avoid water production.At the request of the operator, a post-mortem study was conducted on a horizontal well in the Lower Barnett Shale to determine the cause of excessive water production. Completion optimization studies are typically conducted using wireline tools; however, for the purposes of this study, an advanced LWD logging suite consisting of electromagnetic azimuthal resistivity, neutron, azimuthal density, laterolog resistivity imager, and quadrapole sonic was run on the well. An integrated interpretation of all sensor data was used to first confirm the stratigraphic placement of the well and then evaluate effective porosity, anisotropic closure stress, geologic texture, and natural fracture distribution.Fracture stages and cluster stages were then selected to target similar rock and lowest closure stress along the well, while taking into consideration the existing natural fractures determined from the image log. Fracture-stage placement data, chemically traced production flow, and a flowing temperature log were all used to interpret well flow vs. the actual perforation cluster positions.This paper presents conclusions drawn regarding both the engineering evaluation criteria used to fracture the well, as well as the geologic-based texture and fracture interpretation that explains the ultimate well performance. Finally, a new automatic staging and cluster-placement software solution was employed to use insight gained from the case study well to better plan future horizontal completions within the field.

Pressure Drop Calculation Models of Wellbore Fluid in Perforated Completion Horizontal Wells

Perforated completion is a main method of horizontal well completion. Based on the mass conservation equation, the momentum conservation equation and the variable mass flow in the horizontal wellbore, pressure drop calculation models of the wellbore fluid are established in perforated completion of horizontal wells. The results of calculation and analysis show that the frictional pressure drop, acceleration pressure drop and mixing pressure drop have different effects on total pressure drop of the wellbore fluid, and the frictional pressure drop plays a major role while the acceleration pressure drop and mixing pressure drop have little influence. The liquid viscosity, production and horizontal wellbore length also have different effects on various kinds of pressure drop. When liquid viscosity is smaller and the length of the horizontal wellbore is shorter, the effects of the acceleration pressure drop and mixing pressure drop cannot be neglected. The theoretical basis and the calculation model of the variable mass flow pressure drop of horizontal wellbore are provided.

An Integrated Horizontal- and Vertical-Flow Simulation With Application to Wax Precipitation

Summary There is a lack of comprehensive simulation tools that (a) accommodate the complexities of advanced completions together with near-wellbore behavior and that (b) have reliable wax-precipitation models for production planning. In this work, these issues are tackled by combining three specific models. First, a steady-state, three-phase, nonisothermal flow model in advanced horizontal completions was implemented to run fluid-specific simulations, thereby calculating field-specific flow conditions. This is useful in situations when fluid-specific temperature calculations are important, such as wax crystallization. Second, a nonisothermal, vertical flow model was developed by combining Hagedorn and Brown's multiphase-flow correlation with Ramey's multiphase-temperature model by solving them in sequence (iteratively). The advanced horizontal-well model and vertical flow model were coupled iteratively at the bottom hole where the two models meet. Third, two different analytical wax-crystallization models were incorporated in the aforementioned coupled flow simulator to calculate the location of wax precipitation along the vertical section of the well. These three simulation models, individually and in combination, were tested and found to be in par with theory, expectations, and published results. In addition, a significant difference was noted between Ramey's analytical temperature profile (which is a widely used approximation) and the complete Ramey's model integrated with the simulator developed in this work.