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Totally found 120 items.

  • [会议] Sequencing Hydraulic Fractures to Optimize Production for Stacked Well Development in the Delaware Basin
    Many operators have increasingly moved toward cube development to avoid production impairment due to parent and child wells'fracture-driven interactions(FDI).This cube development technique involves stimulating multiple wells in a section before bringing them online simultaneously or relatively close in time.This implies significant upfront investment to drill and complete in some cases 10's of wells before producing a drop of hydrocarbon from them.Therefore,it becomes critical that the wells are completed optimally to be able to extract maximum resource from the reservoir.Multi-well stacked pad development renders itself as a 4D problem for completion optimization.Well spacing in horizontal and vertical direction and perforation spacing along the lateral being the 3 spatial dimensions,as well as the timing and sequencing of stages add the fourth dimension to the problem.Sensitizing for different sequencing scenarios in the modeling space before operational execution of the stimulation offers a cost-effective way to optimize production.We explore the impact of hydraulic fracturing sequence and spacing on production from the group of stacked wells in a section of the Delaware Basin.A three-dimensional geomodel along with a discrete fracture network is utilized to model a complex hydraulic fracture system created for multiple treatment sequencing and spacing scenarios.Stress shadow from previously stimulated stages is seen to be a major driver in controlling the geometry of the fractures in the wells stimulated later and can be utilized to enhance reservoir contact.Finite element modeling shows the positive impact of the stress re-orientation resulting from previously stimulated stages.Hydraulic fractures confined by stress from outside wells show clear growth pattern into unstimulated sections of the reservoir,thus enhancing the production potential.The stimulated reservoir volume and simulated production are used as key performance indicators(KPIs)for choosing the optimum sequencing and spacing strategy in this study,however the KPI can be changed to meet individual asset needs.This work aims to provide a workflow for modeling stacked well pad development and explores innovative approaches to sequence stimulation stages on wells in order to improve reservoir contact.
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  • [会议] Reducing Well Construction Costs through Field Application of New Unconventional Lightweight Cementing Solutions-Multiple Case Histories in the Permian Basin
    Today's North American land drilling and cementing are facing new challenges due to increased hydrocarbon extraction,especially in the Permian basin.For instance,operators in the region frequently face severe losses during drilling or cementing,which are not prevalent in the other US basins.Lost circulation is a major problem that increases well construction costs and time as well as delays well completion and production in a market where efficiency and costs are the main drivers.Solutions to this perennial problem include two-stage cementing,contingency liners,and use of lightweight cement systems.Lightweight cement reduces hydrostatic pressure to prevent losses particularly in weak formations.Typically,lightweight cements are designed by incorporating expensive micro spheres and/or foam.These designs are relatively costly compared to conventional technologies,and they involve operational complexity in the field.There are other cost-effective materials that allow for designing lower density cements,which have pozzolanic reactivity to increase strength of the set cement.But these traditional materials cannot provide enough compressive strength in the 10.3 ppg to 11.5 ppg density range.In this paper,several case histories will be presented from more than 100 jobs pumped to date.The selected job(s)will be explained with real-time acquisition data,and these data will be compared to pre/post-job computer simulations to explain the dynamics of the placement.Numerous field applications of the novel and cost-effective non-beaded lightweight cementing technology will be described.The new lightweight has a lower hydrostatic pressure during pumping,hence preventing the occurrence of lost circulation.It also delivers superior strength after cement setting,thereby providing better zonal isolation and mechanical support to the casing.Because of its efficient delivery utilizing the same equipment,processes and personnel,this new cementing technology is easily integrated into the current field operations.The novel contribution to the industry is the successful field application of a non-beaded lightweight low permeability cement to more than 100 jobs.This lightweight cement is uniquely formulated with a new unconventional micromaterial that provides superior strength performance,improved operational efficiency,and safety combined with better economics over beaded or foamed cement system.Based on multiple jobs that were completed,this innovative lightweight cement has successfully mitigated losses,thus maintaining lower equivalent circulating densities to achieve the required top of cement.It also eliminated the need for multiple cementing stages,thereby enabling faster well completion and dramatically reducing well construction costs.
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  • [会议] Use of Stranded Natural Gas as a Fracturing Fluid:A Simulation Study
    Due to gas pipeline infrastructure constraints,gas produced in many basins remains stranded.Innovative ways to utilize the produced gas are required.Additionally,the cost of frac-water is high in many areas.In this paper,we conduct a detailed technical feasibility study on using this excess natural gas(NG)as a fracturing fluid.Comparison is also made with typical water-based fluids in terms of fracture propagation,flowback efficiency,and long-term oil and gas production.In this study,we present and utilize a fully integrated 3-D geomechanical,equation-of-state(EOS)compositional hydraulic fracturing and reservoir simulator.The fracturing and reservoir simulations were performed using published datasets from the Permian Basin and experiments on NG foam rheology.The phase behavior of the injected water/gas/foam and reservoir hydrocarbon fluids is considered using an EOS-based compositional calculation.Differences in fracture geometry and fracture/matrix conductivity(proppant embedment and oil flowback relative permeabilities)for foam-based vs slick-water fracturing fluids are compared.An empirical fracture closure model from published experimental studies is incorporated into the simulator during flowback to accurately model the changes in fracture conductivity during production.Well flowback,productivity,and oil/gas production when using NG foams are compared with conventional water-based fluids.Simulation results clearly show that NG foam fracturing fluids achieved improved breakdown pressures,lower fluid leakoff and higher cluster efficiency than slick-water fluids.Due to their higher viscosity NG foams resulted in shorter created fracture lengths with larger fracture width.However,since proppant settling is drastically reduced,the created fractures are much more uniformly propped.Our results clearly show that the improved proppant placement,enhanced stimulated rock volume(SRV)permeability as well as the presence of expandable natural gas around the fractures leads to higher oil production and significantly better unloading and flowback of frac fluids in the case of NG foam.Our results also shown a significant reduction of water usage and considerable natural gas consumption using NG foam for fracturing.In this work we present,for the first time,the detailed technical feasibility of using stranded natural gas as a fracturing fluid.A new fully compositional fracturing-reservoir simulator that captures phase behavior and fracture closure effects while designing completions using non-water based fracturing fluids makes this analysis possible.This study will help shale operators to evaluate the viability of utilizing their stranded gas as a fracturing fluid.
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  • [会议] Water Saturation in Unconventionals:Myth Busted
    Estimating accurate volumetric concentrations of hydrocarbon and water in a producing reservoir is a critical component of predicting well performance,designing well placement and field development planning.Core testing procedures and petrophysical models in unconventional shale reservoirs have always faced the challenges of establishing representative in-situ water and hydrocarbon saturations.When using existing techniques of core calibrated petrophysics,actual well production often varies significantly from expectations.This has a serious impact on the development of major U.S.unconventional plays such as the Eagle Ford,Midland Basin and Delaware Basin among many others.Core taken from these formations enables better understanding what fluids are present and in what quantities.Changes in pressure and temperature as rock is taken from downhole,handled and transported to a laboratory facility,affects the contents of the pore system.Some of the in-situ fluids in the pore space gets volatilized and show up as void space in laboratory measurements.Standard practice calls for treating this void space as previously occupied by oil.Therefore,estimates of hydrocarbon filled porosity are made using the volume of oil extracted from the rock during testing(whether thermally or via solvents)combined with the volume of void space measured.Water filled porosity is assigned a value based on the actual water measured from the rock during the extraction process.However,fluid phase behavior in nano-pore systems is not very well understood.Pore wettability and permeability are also important factors that may control what fluids are lost from the system.Given these uncertainties,the assumption that void space is associated with volatilized hydrocarbon does not hold true.This manuscript will show several experiments including:comparisons between preserved and non-preserved samples,re-testing old core to measure fluid changes with time,nuclear magnetic resonance(NMR)scans,flow-through and fluid imbibition studies among others.NMR T1T2 logs will be used as a downhole water saturation reference.It is shown from these experiments that void filled porosity is usually occupied by formation water.Additionally,log interpretations calibrated to this new water saturation will be shown and compared to well performance.The actual well production agrees well with the above new interpretation.
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  • [会议] Impact of Completions Fluids Chemistry on Hydrocarbon Effective Permeability of Organic Shales
    Techniques such as horizontal drilling and hydraulic fracturing have helped in exploitation of unconventional shale reservoirs.However,a drawback of hydraulic fracturing is that it results in forced imbibition of frac-water into the pore system of the organic shale matrix.This can potentially result in lower productivity emanating from water blockage of oil-wet and oil-bearing nano-pore networks.This paper introduces a laboratory setup to investigate and quantify the damage to oil permeability caused by invasion of fracturing fluids in shales.The proposed process also allows for testing the impact of altering completions fluids chemistry(fresh versus produced water,surfactants,friction reducers,etc)on oil productivity.The technique starts with carrying out micro-CT and NMR scans on as-received shale plug samples to evaluate sample condition and fluid saturations.These samples are then humidified and then saturated with either produced crude,after which a subsequent NMR scan is done to track oil and water saturation.For the permeability measurement,the samples are then loaded in an overburden cell,some of which are made of non-ferrous material and can be loaded in the NMR spectrometer.The sample is brought to reservoir stress conditions by increasing overburden stress and pore pressure gradually.The initial steady state permeability measurement is measured by injecting produced crude or hydrocarbon gases at a constant flow rate using a pump and monitoring pore pressures for stability.The downstream pressure is controlled by a back-pressure regulator.Once steady state flow is established and the baseline effective hydrocarbon permeability is measured,a brine or a fracturing fluid solution is injected into the sample from the downstream side(frac face)for a specified time period.The completion fluid injection pressure is typically about 1000 psi to 2000 psi higher than the upstream oil pressure to simulate hydraulic fracturing induced imbibition of water.Then,to mimic shut-in that follows hydraulic fracturing of a stage,the upstream and downstream valves are closed for about 12 to 24 hours.Finally,hydrocarbon permeability is measured again as was done initially,to quantify degradation of deliverability due to water imbibition.Saturations of hydrocarbon fluid and brine in the sample are calculated using NMR T2 and T1T2 scans either during the test or right after the test is complete.In some instances,the saturation front of the hydrocarbon fluid or injected brine is examined using 2D and 3D gradient NMR scans.These tests can be conducted at high pressure and temperature,while the setup that involves continuous NMR scanning of the plug during the core flooding process is rated to 10,000 psi for overburden pressure,9000 psi for reservoir pressure and 100 C for reservoir temperature [Mathur et al.2020].Permeabilities as lows as 5 nano-Darcies have been measured.Varying completions fluids chemistries(salinity alteration,KCl,surfactants,FRs,etc)can also be used in the setup to evaluate the benefit or lack thereof in minimizing permeability damage.On average,a decrease of 70% in hydrocarbon productivity is observed on comparing initial permeability and final permeability after water damage.As a validation of the water block phenomenon,samples have also been injected with decane and diesel from the bottom(frac face)and little to no damage in hydrocarbon productivity is observed.Some scenarios of adding surfactant mixtures to the frac water,as well as cyclic gas injection have shown initial positive results;and are active areas of study.
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  • [会议] Characterizing natural fractures and sub-seismic faults for well completion of Marcellus shale in the MSEEL Consortium project,West Virginia,USA
    The Middle Devonian Marcellus shale play has emerged as a major world-class hydrocarbon accumulation and represents one of the largest and most prolific shale plays in the world.According to many outcrop studies in the region,natural fractures are well developed in the Marcellus Shale.However,evaluating fractures in the subsurface is often a significant challenge due to a lack of sufficient data.Therefore,in the Marcellus Shale Energy and Environment Laboratory(MSEEL)consortium project,significant efforts have been made to acquire high-quality image logs in the Marcellus laterals.The project provided tremendous opportunities to characterize the natural fractures and sub-seismic faults and to evaluate their impact on well stimulation.In this study,about 70,000 ft of acquired high-resolution logging while drilling(LWD)acoustic images from five long laterals located in Monongalia County,West Virginia,were processed and interpreted.In addition,the study used high-quality micro-resistivity images from a pilot well,allowing the evaluation of natural fractures in the entire Marcellus vertical sequence.Based on the available acoustic images,the natural fractures were classified into three basic categories:high-amplitude fractures,low-amplitude fractures,and faults.Further,larger open fractures can also be determined when a low-amplitude fracture is evident on caliper images.The fractures in the Marcellus usually have a medium to high angle dip;however,multiple fracture sets in terms of strike orientation were clearly observed in all the laterals.The fracture set with a strike at NE-SW(or 60-240 deg)seems to be the predominant one in all the wells.A few other sets,including those with N-S,NWW-SEE,and E-W strikes,were also observed.Several sub-seismic faults,with mostly a low dip angle and a NE-SW strike,have also been seen in two of the laterals.The fracture density is variable across all the laterals,ranging from very low(or none)to very high(up to 5 fractures per ft).The average fracture density for all the laterals is about 1 fracture per 10 ft.In the vertical sequence,the natural fracture development showed a clear preference for shale or shaly facies over carbonate-rich or thin limestone layers.The interpreted fracture and fault data were used as input data for the stimulation design with the purpose of better understanding the fractures'impact on well stimulation.Production data from the laterals were also used to evaluate the natural fractures'influence on well performance.The quality image database and the consistent interpretation results for the entire project enabled a systematic approach to characterizing fractures and,more importantly,to evaluating the impact of fractures on well stimulation and production.
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  • [会议] Novel Sulfide Scale Inhibitor Successfully Averts Challenging Sulfide Scale Deposition in Permian and Williston Unconventional Basins
    Sulfide scales(zinc,lead and iron sulfide)are currently causing considerable production challenges as mature fields are kept operational,and as deeper-hotter reservoirs are been developed.An effective way to combat conventional scaling is to inject"squeeze"scale inhibitors into the formation which are then slowly released as production resumes,providing scale protection.This option has not been the case for sulfide scales due to formation kinetics and lack of suitable products.In this study we present two field cases where new generation squeezable sulfide inhibitors were deployed with clear success in inhibiting sulfide deposition and establishing stable production.Also presented are the development methods and chemical synthesis details for the development of a squeezable product.A novel fast screening technique is detailed as well as a new type of residual monitoring method for the polymeric species that inhibit the sulfide scales.In the Permian Basin,newly completed long horizontal wells in the Sprayberry Formation were on a constant rotation of work overs(every 3 to 5 days)due to severe zinc and iron sulfide deposition.Early squeezes performed with known phosphonate/ester scale inhibitors,and end-capped polymer were unsuccessful.A new generation of squeezable sulfide inhibitor was deployed and stabilized production as well as the scaling ion data.A unique and fast residual analysis methodology(using a specialized HPLC column)was developed as part of the squeezable sulfide inhibitor development project capable of providing a unique selectivity in a high TDS brine without interferences increasing residual monitoring and squeeze confidence.In the Williston basin many fields are known for their troubled history with iron sulfide.To date,the preferred option has been continuous well cleanout that impacts production,next generation squeezable sulfide inhibitor was deployed and it successfully increased productivity and eliminated well clean outs for the trialed wells.This technology summarized in the paper offers a substantial step change in the ability to protect against sulfide scale via squeeze application.These field treatments show that next generation squeezable inhibitors were successful in inhibiting sulfide scales with no observed formation damage,upset to process facilities during flow back,or decline in productivity.
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  • [会议] A Comparison of Hydrocarbon Extraction Techniques:Trying to Make a Mountain from a Mole Hill
    Petroleum geochemistry applications have evolved and developed during the unconventional boom of the past 10 years as operators have expanded rig rates and grown production numbers.Most unconventional plays primarily target the source rock,and petroleum geochemists have used this decade to further develop their understanding of source rocks and the generation and expulsion of hydrocarbons.One geochemistry application that has been expanded during this period is the process of extracting hydrocarbons from source/reservoir material and comparing this to produced hydrocarbons.This practice has been applied in unconventional plays to discern more discrete relationships with the goal of using extracted hydrocarbons to confirm a correlation to the acting source/reservoir that provides economic production.Combined with other geochemical and multidisciplinary datasets,these types of projects aid in many practical aspects of unconventional development programs,such as confirming landing zones,drainage height of frac zones,and defining effective source rocks.While it is generally acknowledged that the laboratory extraction process is not a perfect replication of naturally generated and expelled hydrocarbons,it is clear that useful correlations can be made.However,there are a variety of different extraction methods,and these different methods can yield variable quality of extracts.While most practitioners have been careful to confirm and report their methods and success with extract work,there are few published studies that show direct comparisons of different extraction methods in a controlled setting(Johnson and Lusas,1983;Kornacki,2019).This lack of data makes it difficult for operators who are designing geochemistry studies that involve hydrocarbon extractions,to judge which method is the most appropriate for their immediate purpose.In this paper,we explore a direct comparison of several different extraction methods,carried out in a controlled and consistent environment,under conditions most similar to typical unconventional petroleum geochemistry projects:"warts and all"if you will.The purpose is not to judge which is the'best'method-the authors acknowledge that different methods may be required to meet different experimental goals-but rather,establish how significant the differences are between the methods.We will also discuss which method might be the most appropriate to use when attempting to compare an extract to a produced oil.Because this work is an application to unconventional plays,the analysis will be focused on extract methods that provide the best preservation of light end hydrocarbons(nC4-nC20).Most unconventional plays produce light hydrocarbons(LHC)that are more mobile in tight reservoirs.Therefore,while C15+ components are often critical for genetic interpretation of oils in any play type,they may not be the focus for operators with smaller scope programs or production focused projects,especially in thermally mature areas.
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  • [会议] Carrier Bed(Halo)Play in the Cretaceous Turonian Turner Sandstone,Crossbow Field Area,Powder River Ba
    The goal of this work is to present a new type of unconventional play(carrier bed/halo)that is developing in the Powder River basin.This play is being developed via the combined technologies of horizontal drilling and multistage hydraulic fracturing.The Turner sandstones of Turonian age is a target of exploration and development in the Powder River basin.The sandstones are interpreted to be marine shelf sands.The Turner Sandstone is a prolific reservoir in the Crossbow area of the Powder River Basin.The area is being developed with horizontal wells at vertical depths of 9400 to 12000 feet.Initial production from horizontal wells ranges from 500 to 1700 BOPD and 1000 to 4000 MCFGPD.The carrier bed(halo)play is downdip and an extension from older vertical Turner production in the School Creek,Porcupine,and Tuit Draw fields.The Crossbow area is overpressured with no known water contacts(updip or downdip).The Crossbow area includes the Crossbow,K bar,Mary Draw and Horse Creek fields which have now merged into a larger producing area.Source beds for the Turner Sandstone include the overlying Niobrara,and Sage Breaks shales and underlying Mowry,Belle Fourche,Greenhorn,and Poole Creek shales.Source bed maturity occurs in the deeper part of the basins.Oil and gas migration into the carrier beds results in regional pervasive hydrocarbon saturation.Discrete traps that have been previously developed are part of a more extensive hydrocarbon system and ultimately may merge into an extremely large area of continuous production.
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  • [会议] High Resolution Cuttings Analysis for Well Placement in the Uinta Basin
    The Uinta Basin is known for its lacustrine depositional environment and its high lateral variance that makes it challenging to predict and characterize petrophysical properties.In this study,a formation evaluation workflow is presented that extracts geochemical and geomechanical data for a lateral section of horizontal well.Then the obtained data was benchmarked to production,completion and core laboratory testing data to identify the best landing targets.For this case study,four wine rack placed wells were analyzed for geochemical and geomechanical properties.Wine rack wells were drilled in Uteland Butte and Wasatch formations within the Uinta Basin.First,high-resolution drilling cuttings were collected at pilot wells.Cuttings were analyzed for mineralogy using X-ray diffraction(XRD),elements using wavelength dispersive X-ray fluorescence(XRF)and total organic carbon(TOC)using pyrolysis.Subsequently,considering the geomechanical aspect,a stress profile was generated from well log data by assuming isotropic material.Young's modulus and Poisson's ratio values obtained from rock mechanic testing on the vertical core as well as DFIT results were used to validate the model.Utilizing the core's mechanical properties and mineralogy,rock physics modelling was used to find the best theoretical bounds.The bounds can be implemented to predict mechanical properties using mineral composition from cuttings samples.Afterward,the stress profile from cuttings analysis can be compared with the geophysical log.It was identified that the rock physics model of core data follows the Reuss-bound trend.It explains that the rock is layering horizontally,validating the isotropic assumption when calculating the rock physics model.Since the mineral composition of cuttings samples match the core,the Reuss model can be applied to the cuttings data to calculate rock mechanical properties and the stress profile.The generated stress profile from the geophysical log has less variability than the rock components,as the Biot's coefficient is usually assumed as a constant.On the other hand,using a rock physics approach,the Biot's coefficient can be predicted.In the Wasatch Formation interval,the stress profiles from both the geophysical log and rock components show that there is a stress barrier,which is more pronounced in the latter.Completion strategies on the four horizontal wells are similar with the Uteland Butte wells showing the highest cumulative production.The low flowable hydrocarbon index explains the lower production on Wasatch wells.Moreover,the observed stress barrier prevents vertical growth of the hydraulic fracture which leads to less access to hydrocarbon.This study shows that cuttings analysis provides valuable information and better decision input to identify more productive wells.
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