Slanted Wells Research Articles

Foamed Cement Mitigates Gas Migration in Shallow Thermal Wells in Alberta

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214768, “Mitigating Gas Migration Using Foamed Cement on Shallow Thermal Wells in Northeast Alberta,” by Charles Sylvestre, SPE, Sanjel Energy Services; Julio Oliveira, Suncor Energy; and Heyong Jiao, Sanjel Energy Services. The paper has not been peer reviewed. _ A foamed cement solution was designed and implemented to cement shallow intermediate casing strings in a heavy oil play in northeast Alberta after conventional area-specific cementing solutions could not prevent surface casing vent flows. Foamed cement was pursued as a better alternative technical solution and ultimately led to its successful placement in the field. Significant technical and operational hurdles were overcome to confirm proper well control and ensure that the energized cement could be pumped safely and effectively. Introduction MacKay River is Alberta’s shallowest steam-assisted gravity drainage (SAGD) project, with wells typically ranging between 100 m and 150 m true vertical depth (TVD). Wells have been drilled recently at MacKay River with a horizontal length approaching 1000 m and total length exceeding 1500 m measured depth (MD). Wells at MacKay River are drilled using a slant rig because of the extremely shallow depth of the reservoir. The wells feature a three-string casing design with a shallow surface casing, an intermediate casing that runs from surface to the target formation and is landed at 90° inclination, and a horizontal production (or injection) liner hung off the intermediate casing. The intermediate casing is cemented in place and uses premium connections incorporating a metal-to-metal seal to provide a barrier between wellbore fluids and the formations overlying the reservoir. The complete paper discusses a new pad at the MacKay River SAGD operating site. The specific operations discussed are those involving intermediate cementing. Case-Well Challenges One of the most unusual features of the case wells was the discovery of gas trapped under a shallow formation at approximately 80–100 m vertical depth. The pad adjacent to this new pad has been in operation for 17 years. The second obstacle was the hole and casing size, which creates a large annulus. The open hole size was designed at 374.7 mm with the intermediate casing sized at 298.5 mm. This creates an annular gap of 38.1 mm in a gauge hole, but typically these wells require 150% cement excess to achieve cement returns to surface, meaning that, in certain areas of the well, the annulus is much larger. The next challenge presented by the case wells is that they are slanted wells, spudded at an angle of approximately 45° from the surface. The low temperature of these wells also adds to the complexity of preventing gas flow. At such low temperatures, cement sets much slower than in other well types. Finally, the shallow nature of the well, landing at only 113 m vertical depth, does not allow effective hydrostatic pressure control while the cement sets.

Natural fracture mapping and discrete fracture network modeling of Wolfcamp formation in hydraulic fracturing test site phase 1 area, Midland Basin: Fractures from 3D seismic data, image log, and core

Fractures control fluid flow in ultra-low permeability reservoirs due to their much higher permeability. Recognition, mapping, and characterization of both natural and hydraulic fractures at multiple scales are critical to predicting hydrocarbon production in tight rocks, including mudrock. However, this determination is very challenging due to data scarcity, varying data resolutions, and uncertainties in interpretations. In this research, we combined core-identified fractures, image log-identified fractures, and 3D seismic data to analyze natural fracture features of, and construct a discrete fracture network (DFN) model for, the Wolfcamp Formation in the Hydraulic Fracturing Test Site Phase 1 (HFTS-1) project area in the central Midland Basin of the United States. An azimuth-guided, ant-track seismic attribute called VarAntAntPas was developed to recognize natural fractures and extract their seismic discrete planes (SDP) at multiple dip azimuth ranges. The extracted SDPs were then employed to calculate the fracture length, height, and elongation, as well as the dip angle and dip azimuth. This process revealed a limitation of recognizing natural fractures shorter than 600 ft by 3D seismic data due to its resolution. To model fractures shorter than 600 ft, we calculated fracture intensity at different dip azimuths from the VarAntAntPas attributes and combined this variable with fracture dip angle derived from well data and the extracted SDPs. The extracted SDPs for larger fractures (length >600 ft) and the modeled smaller fractures (length <600 ft) were combined to build a DFN model of the Wolfcamp Formation in the HFTS-1 project area. Clearly, the DFN model was built with different ways for two different-size fracture groups. Meanwhile, the discrete fractures in different orientations were built independently and then combined together in the DFN model. Natural fractures predicted by the DFN model were then validated by comparison to fractures identified from core and image logs from two horizonal wells and one slant well in the HFTS-1 project area.

Analysis on the pressure dynamic characteristics of slanted well in dual-porosity and dual-permeability reservoir

In order to understand the dual-permeability flow law of slanted well in a fractured reservoir and study the characteristics of pressure dynamics, a flow model of slanted well in a dual-porosity and dual-permeability reservoir is established. The model is solved by Laplace transformation, separation of variables, and superposition of sink source functions, etc. The analytical solution of bottomhole pressure change in Laplace space is obtained. A series of pressure dynamic characteristic curves of slanted well in dual-porosity and dual-permeability reservoirs are programmed and drawn by Matlab software, which are controlled by varying model parameters such as the permeability ratio of fracture system to total system. Based on the pressure dynamic characteristic curves, seven flow regimes are identified, including pure well bore storage effect stage, skin effect stage, early radial-flow, middle linear-flow stage, transitional flow stage, inter-porosity flow stage from matrix to fracture and late radial flow stage. In particular, the differences of flow characteristic curves among slanted well, vertical well and horizontal well are analyzed. It is found that slanted well has more early radial-flow stage and middle linear-flow stage than the vertical well, and these two flow regimes have shorter duration than the horizontal well. In addition, the effect of inclination angle of well, well length and other parameters on the characteristic curve is analyzed. The larger the inclination angle and well length, the lower the curve position, the more obvious the early radial flow stage and the middle linear flow stage. The larger the permeability ratio of fracture system to total system is, the more significant the inter-porosity stage is and the deeper the inter-porosity concave is. The proposed analytical model and a series of pressure dynamic characteristic curves can be used to study the seepage characteristics of slanted wells in fractured reservoirs. <fig fig-type="abstract-image" id="F1" orientation="portrait" position="float"><graphic xmlns:xlink="http://www.w3.org/1999/xlink" xlink:href="1000-2618-2022-39-6-660/D5477531-C4E9-4093-9DA1-A06C4F43D821-F001.jpg"/></fig>

INSIM-BHP: A physics-based data-driven reservoir model for history matching and forecasting with bottomhole pressure and production rate data under waterflooding

In this work, we present a new physics-based data-driven interwell three-dimensional (3D) numerical simulation model with front tracking. It provides accurate and computationally fast calculation of bottomhole pressures (BHPs) for history matching, forecasting, and well-control optimization for a 3D reservoir with slanted wells with sectionally perforated intervals under waterflooding. The new model is referred to as INSIM-BHP. The previous versions of INSIM-based models cannot accurately generate BHPs since they use the upstream saturation (or upstream weighting) to obtain the transmissibility of each connective unit and neglected the changes of total mobility and the gravitational effect while water front propagates. INSIM-BHP implements harmonic average transmissibility and fine-scale gravity term calculations to accurately represents flow between a pair of connected nodes by making use of fine-scale saturation distribution calculated by front tracking. Besides, unlike the previous versions of INSIM-based models, it approximates oil reservoirs associated with limited volume aquifer drive systems. The accuracy of the BHPs generated with INSIM-BHP is validated by comparison with corresponding results from a high-fidelity commercial simulator (Eclipse 100™1) considering two synthetic T-shaped reservoir examples with complex gravitation effects with fine grids and small-time steps. Results show that INSIM-BHP model provides accurate BHPs that agree quite well with the corresponding BHPs computed from Eclipse 100 (less than or equal to 2 psi for these two synthetic examples considered in this study). We test INSIM-BHP by history matching three different sets of observed data types for a synthetic 3D channelized reservoir; (1) well oil production rate only; (2) BHP only; (3) oil production rate and BHP simultaneously. Results show that INSIM-BHP with harmonic average transmissibility and fine-scale gravitational term provides a better history matching and prediction ability for well oil production rate and BHPs performance. We have validated our aquifer modeling approach used in INSIM-BHP with an Eclipse's Fetkovich-based aquifer model and presented an application of INSIM-BHP to history match and predict oil production rate and BHP from Brugge model, a field scale synthetic reservoir model.

On the discharge variation of a qanat in an alluvial fan aquifer

Qanat is a passive (unpumped) horizontal well (or a slant well with a very mild inclined angle) that is capable of extracting water from aquifers by gravity. Many qanats are constructed along the radius of the alluvial fan wedge-shaped aquifers. Analytical modeling of such a qanat-aquifer system provides great benefit for quickly screening different designs of qanats and accessing the performance of qanat discharge in the field. The previous analytical modeling of discharge of qanats, however, did not consider the wedge-shaped aquifers. Thus, the goal of this research is to obtain semi-analytical solutions of discharge variations of qanats in alluvial fan aquifers with nearby pumping wells, subjected to areal recharges due to rainfall. The uniform head boundary is considered inside the qanat (because of its enormous permeability in respect to the background aquifer). The influences of the aquifer lateral boundaries on discharge of qanat and its sensitivity to hydraulic and geometric parameters are explored. The influences of the lateral boundaries on the discharge of qanat due to areal recharge and nearby pumping wells discharge are also explored. The results of this study can be utilized for multiple purposes: 1) to predict the discharge of qanat in an alluvial fan aquifer and explore the influences of the areal recharge and nearby pumping well discharge; 2) to estimate the hydraulic parameters of the alluvial fan aquifer depleted by a qanat; 3) to determine the location of the nearby pumping well to minimize its influences on the discharge of a qanat; 4) to calculate the water budgets of aquifers depleted by qanats and pumping wells and replenished by areal recharge among other applications. This paper is an extension to the work presented by Sedghi and Zhan (2020) (which concerns an infinite unconfined aquifer) for an unconfined alluvial fan aquifer setting.

Production Performance Analysis for Deviated Wells in Carbonate Gas Reservoirs With Multiple Heterogeneous layers

Deviated wells are used to improve the performance of carbonate reservoirs with multiple heterogeneous layers and penetrate the “sweet spot” of each layer, which is full of fractures and vugs. It is difficult to consider in-layer and inter-layer heterogeneities simultaneously, and predict the production performance for these wells accurately. Therefore, a semi-analytical model to analyze the production performance of deviated wells in a multilayer heterogeneous stress-sensitive carbonate gas reservoir is proposed. For each layer, the inner region is a fractured-vuggy porous medium, while the outer region is merely a tight formation with matrix and formation properties, and penetrated inclination angles may be distinct. Pseudo-time/pressure factors are introduced to consider fracture stress sensitivity. Through the application of Laplace transformation, Fourier transform and inverse, Duhamel convolution, and Stehfest numerical inversion, the presented model is solved. The validity of this model is verified through comparison with single-layer composite formation with different porous mediums and vertical well in a multilayer carbonate gas reservoir. Moreover, by matching bottom-hole pressure data collected from a slanted well in the Anyue gas field, the applicability of this model is validated. A synthetic case, which has two composite formations, the first (upper) layer is more permeable than the second (lower) layer, is used to study the variations of inner region radius, fracture/matrix permeability, and inclination angles on production behaviors. The results show the properties of the first layer determine well bottom-hole pressure, whereas the rise of permeability, inner region radius and penetrated angle for the second layer can improve the gas recovery of this layer. In practice, to maintain well bottom-hole pressure with a relatively high level and enhance gas recovery of the tight layer, the inclination angle should be larger than 60° for each layer, and be increased to as large as possible. The findings of this study can help for a better understanding of the production behaviors of deviated wells in multilayer heterogenous reservoirs and could provide some guidance for the design of well trajectory.

An adaptive moment estimation framework for well placement optimization

In this study, we propose the use of a first-order gradient framework, the adaptive moment estimation (Adam), in conjunction with a stochastic gradient approximation, to well location and trajectory optimization problems. The Adam framework allows the incorporation of additional information from previous gradients to calculate variable-specific progression steps. As a result, this assists the search progression to be adjusted further for each variable and allows a convergence speed-up in problems where the gradients need to be approximated. We argue that under computational budget constraints, local optimization algorithms provide suitable solutions from a heuristic initial guess. Nonlinear constraints are taken into account to ensure the proposed solutions are not in violation of practical field considerations. The performance of the proposed algorithm is compared against steepest descent and generalized pattern search, using two case studies — the placement of four vertical wells and placement of 20 nonconventional (deviated, horizontal and/or slanted) wells. The results indicate that the proposed algorithm consistently outperforms the tested methods in terms computational efficiency and final optimum value. Additional discussions regarding nonconventional parameterization provide insights into simultaneous perturbation gradient approximations.

A new method for monitoring wells productivity index dynamics

А method for monitoring wells productivity index dynamics from the moment of its start-ups is proposed. It allows detecting candidates for conducting well tests (WT) and well interventions for the increase of a daily production. The method is based on an integral analysis using pressure maps and well tests. Application of this method on the Salym group of oilfields has allowed concluding about wells stock status, about productivity index dynamics in time, also to make an assumption about the reasons for its change. The analysis showed that productivity index relative changes in horizontal wells lower than in slanted wells.

Sand Blocking Mechanisms and Productivity Analysis of Slant Well in Siltstone Reservoirs

The siltstone reservoir with many small layers of pay zones is usually produced by slant holes. However, severe sand blockages take place when the siltstone reservoir is developed by slant holes. Currently, the sand blocking mechanisms and the effect of sand blocking on productivity of slant well are still challenges for engineers and scholars. In this paper, based on the existing productivity model of inclined slant wells, the mechanical skin factor, which describes the effect of sand blocking on productivity, is proposed. Meanwhile, many experimental works have been done to investigate the sand blocking mechanisms in siltstone reservoirs. From the experimental work, it is concluded that with the increase of displacement PV number and displacement flow rate, the permeability of sand control system decreases by 40%. When solid particles enter the casing and block the gravel and sand control screen in the annulus, the skin factor increases sharply and the productivity decreases by more than 80%. Through the productivity calculation of multilayer sand control wells, it is considered that larger gravel packing radius can keep particles away from the well bore, which is helpful to ensure oil well productivity. Furthermore, the influence of differential filling radius on the fluid production capacity of each layer of sand control well is analyzed. It is proved that optimizing the filling radius of each layer can improve the production effect of mediate- and low-permeability layers. This method has been applied in Kendong #12 block. The daily oil production rate is increased by 9.61 t/day, and the oil recovery of this block is increased by 2.12%.

Production performance analysis for slanted well in multilayer commingled carbonate gas reservoir

This paper proposes a semi-analytical model to evaluate the production performance for slanted wells in a multilayer commingled carbonate gas reservoir, in which the porous medium types and penetrated angles for each layer may be distinct. The triple-porosity/single-permeability and single porosity/permeability models are utilized to describe the fluids flow in natural fractured vuggy and tight formations, respectively. In addition, the stress sensitivity for different formations is considered in pseudo-time and pseudo-pressure. Laplace transformation, Fourier transform and inverse, Duhamel convolution, Stehfest inversion, and point source function are used to calculate the well bottom-hole pressure and production rate for each layer. After proper simplification on the proposed model, the calculated results match very well with the classical solutions in published papers. Furthermore, the accuracy of this model is validated by comparing the well bottom-hole pressure with the monitored data of a well in the Gaoshiti-Moxi carbonate gas reservoir. A synthetic case, which contains two layers that the upper one is naturally fractured vuggy formation and lower one is tight formation, is constructed to analyze the variation of horizontal-vertical permeability ratio and penetrated angles on production performance. The results show that the horizontal-vertical permeability ratio and the penetrated angle in naturally fractured vuggy formation determine the level of well bottom-hole pressure, while these two parameters have significant influences on production rate for tight formation. In practice, to enhance the gas recovery of tight formation, and to keep the well bottom-hole pressure a relatively high level, for tight and naturally fractured vuggy layers, the penetrated angles should be larger than 50° and 45°, respectively, and be increased as large as possible. • A semi-analytical model for slanted well in multilayer commingled carbonate gas reservoir is presented. • The geology characteristics and penetrated angles for individual layer can be various. • The effects of formation anisotropy and penetrated angles on production behaviors are evaluated. • The critical values of penetrated angle for different types of formations are determined.

Harvesting geothermal energy with low unit cost installations

In the Netherlands, most geothermal energy is utilized for commercial greenhouse heating and is harvested from aquifers located at depths between 2 and 3 km. Typically, the design consists of two wells: a slanted production well and a slanted injection well that are spaced approximately 1.5 km apart in the aquifer formation. Subsidized exploitation is feasible if high volumes can be produced over long periods of time. This typical solution restricts the use of geothermal energy to high-demand applications in areas with suitable high-quality aquifers. We argue that harvesting geothermal energy is economically feasible almost anywhere in the Netherlands with an alternative concept of low unit cost (LUC) installations. LUC produces at a limited rate from cleverly designed high-quality installations that can be developed at a considerably lower cost. We discuss the LUC concept and its economics based on a project for commercial greenhouse heating in the eastern part of the Netherlands. We carry out a reinterpretation of publicly available 3D seismic and offset well data. The Early Cretaceous Bentheim Sandstone was identified as a suitable aquifer for LUC development. At the proposed well location, the top Bentheim is located at a depth of approximately 1500 m, corresponding to about 61°C. We predict a reservoir thickness of approximately 54 m, with a porosity of up to 25% and sufficient permeability. The LUC concept begins by drilling a pilot hole for static and dynamic aquifer characterization. Based on these test results, we decide on the final architecture and placement of wells. Our calculations show that a 1.5 megawatt thermal (MWth) geothermal plant is economically viable, even without government subsidy.

Determining Attributes of Finite Fracture Networks in Low-Permeability Carbonate Reservoirs

SummaryCarbonate reservoirs usually consist of multiple units each with different degrees of layer-bound fracture density, height, length, and angular scatter. Some units may have finite fracture networks (FFNs), and some others may contain only isolated fractures. FFNs are islands of interconnected fractures within a sea of isolated fractures. The fracture volume can be estimated from the initial surge in production if a wellbore intersects only a single FFN. Combining with fracture density and aperture measurements from borehole images, FFN volume, drainage area, and other relevant attributes can be calculated. If, however, a slanted well intersects an unknown number of FFNs each in a different unit, it is not possible to estimate each FFN fracture volume from initial fracture production. Because the connectivity threshold for initiation of FFNs is not known or cannot be calculated, it is not possible to determine how many FFNs the borehole intersects. One way is to set an arbitrary threshold of fracture connectivity, λc.Based on this initial value, a fracture-flow model can be generated and adjusted until the inferred rate time and cumulative time curves converge to observed values. The adjustment is accomplished by changing the number of FFNs using different connectivity threshold λc and estimating their size by modifying unknown or uncertain parameters such as fracture aperture. The final model yields the mostly likely number and size of all FFNs and provides an approximate forecast for future production performance.The ability to match production performance without taking pressure into consideration shows that rate decrease in fractured reservoirs with FFNs is not only related to pressure drawdown but also, perhaps more importantly, to depletion of FFNs starting from the smallest size or the one with highest drainage efficiency.One drawback of the method is that different numbers of FFNs may have similar inferred production performance and cumulative production. This is an inevitable drawback inherent in most models that must rely on multiple uncertain or unknown parameters. The only way to decrease the range of possible solutions is to decrease the uncertainties in the underlying input parameters. In any case, alternative results may be presented as a range of possible solutions.

Multilateral Offshore Well Completed With Multistage Proppant Fracturing

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194324, “The World’s First Offshore Multilateral Well Completed With Multistage Proppant Fracturing: A Case Study From Offshore Black Sea,” by Andrew Tomlins, OMV; Joel Conrad, SPE, Packers Plus; and Bogdan Bocaneala, OPECS, prepared for the 2019 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 5–7 February. The paper has not been peer reviewed. The complete paper discusses the successful execution of the first offshore multilateral well completed for multistage high-pressure proppant stimulation, according to the authors, in the Black Sea offshore Romania. The authors discuss the drivers that led the operator to trial a multilateral well; the selection, planning, and final completion solution; and the lessons learned. Field Background Lebada Vest, located 95 km offshore northeast of the city of Constanţa, is the largest offshore Romanian oil field currently in production. It was discovered in 1984 and has been in production since 1993, and thus now faces the challenges and strong investment requirements associated with a mature field. Hydraulic fracturing has been used in the field’s low-permeability-formation wells since 1992, mainly in vertical or slanted wells. Completion Challenge With only one platform slot left and a significant undrained area of the reservoir, the operator had to maximize hydrocarbon recovery through a single well which, because of pressure to increase daily production, had to be finalized in 1 year. Building on field experience gained since 2008 in multistage proppant stimulation, a detailed screening and evaluation of multilateral completion technologies was performed. The focus was on developing a concept that would minimize risks during execution while meeting cost and lead-time objectives, which necessitated customizing the chosen Technology Advancement for Multilaterals (TAML) Level 3 completion design and installation methodology. To maximize rig-time efficiency, the well was executed in two phases: Drilling and lower completion installation of both branches with a drilling rig Stimulation and upper completion installation with the platform’s workover rig With six stages in each lateral, the high-pressure stimulation was executed by a converted supply vessel in four sailings, necessary to reload materials. To meet the delivery schedule, ensure simplicity, and leverage operator experience, the completion was undertaken with no dedicated multilateral hardware. Instead, the operator used standard, multistage, stimulation openhole completion equipment and appropriately engineered bent joints to exit the main bore. With initial production rates higher than anticipated, the well proved considerably more economical than drilling two horizontal wells with equivalent reservoir coverage. The success of this well serves as a proof of concept and provides increased confidence in delivering reliable, cost-effective, multilateral wells, even under tight time constraints and in areas or with operators with no history of multilateral completions. Identifying Multilateral Completion Requirements The operator’s field-development team investigated single, dual, and trilateral well-design feasibility against agreed design criteria. The principal objective was to maximize the chance of success through an appropriately risk-minimized design using standard, field-proven tools and techniques. Completion-design criteria were carried from the previous (single-lateral wells) field-development campaign in terms of production objectives, intervention capabilities, and logistics. The complete paper discusses the effect of general well design, junction, stimulation, intervention, rig strategy, and logistics and experience on the completion requirements.

A NEW METHOD OF DECLINE CURVE FORECASTING FOR PROJECT WELLS ON THE BASE OF MACHINE LEARNING ALGORITHMS

The article describes new decline curves (DC) forecasting method for project wells. The method is based on the integration of manual grouping of DC and machine learning (ML) algorithms appliance. ML allows finding hidden connections between features and the output. Article includes the decline curves analysis of two well completion types: horizontal and slanted wells, which illustrates that horizontal wells are more effective than slanted.

Transient deliverability evaluation for a slanted well in a slab gas reservoir

ABSTRACT The present work provides an algorithm to calculate transient deliverability of a slanted well in a slab gas reservoir. Firstly, transient pressure response of a slanted well has been analyzed and the solutions in Laplace space under three boundary conditions have been derived by point source function and Green function. The solutions in real space can be obtained through the Stehfest inversion by using the superposition principle. Based on the transient pressure analysis, a transient productivity analysis method has been presented in this paper. The influence factors of productivity such as the deviation angle of a slanted well, perforation length, permeability anisotropy ratio, and horizontal permeability to the IPR curve and open-potential rate have been discussed.

English

Inflow-control devices (ICDs) were developed to avoid coning problems in long horizontal wells mainly in heterogenous formations, but cause some additional drawdown which does not contribute to rate increase. This rate reduction is seen to be impairment to the productivity of horizontal wells. Therefore, horizontal wells that are equipped with ICDs require a pre-quantification of their productivity by determining skin caused by each ICD nozzle size. This will help prevent additional expenditure that will be spent for a corrective horizontal well intervention. Many authors have proposed equations that can be used to estimate skin due to damage, partial completion, slanted well and perforation. No author has provided a skin equation that can be used to estimate recoverable and productivity loss that may result from the use of inflow control devices. In this work, a 3D numerical model which includes inflow control devices along horizontal wells was used to investigate reservoir and production performances of various ICD nozzle sizes. Different productivity losses from different nozzle sizes were seen as skin and a 0.002ft2 ICD nozzle flow area estimated to have a zero skin. Consequently, a simple equation for calculating this skin due to restricted fluid entry through ICD nozzles was derived. The derived equation which shows insignificant deviation from skin equation is then used for selecting the right nozzle size for production and recovery optimization from horizontal wells. Key words: Inflow control device

A Look Into What Fractures Really Look Like

Reports from the Hydraulic Fracturing Test Site offer a glimpse into what hydraulic fractures really look like. The featured attraction in the 13 technical papers presented over two mornings at the Unconventional Resources Technology Conference (URTeC) was 600 ft of rock fractured in late 2015 near wells in the upper and middle Wolfcamp. Those core samples spawned a mind-boggling array of observations about the rock, proppant, and natural and hydraulic fractures, and how they all interact. In the more than 2 years since the samples were gathered, the sections of core have been meticulously analyzed by teams of experts. More than 700 fractures were categorized based on whether each one was created by nature, hydraulic force, or the stress of drilling the slant well. And the majority of the 400 stages pumped were studied using tracers and/or monitored using advanced diagnostics. The density and distribution of the fractures were measured as the scientists worked to understand how natural and hydraulic fractures interact. The bits of sand, calcite, and drilling mud found in and around the rock were collected and sorted. Automated imaging and painstaking manual examinations were used to measure the size, shape, and translucence of each grain in order to identify and quantify the grains. The “incredible complexity” observed was “far beyond what current simulations can model and predict,” said Jordan Ciezobka, manager for research and development for the Gas Technology Institute (GTI), which managed the federal grant supporting test site 1 and is planning Hydraulic Fracturing Test Site 2 (URTeC 2937168). Ciezobka predicted that findings from the first Permian test site hosted by Laredo Petroleum in the Midland Basin would be studied for years to come. The public-private partnership is just beginning to deliver the delayed reports of what it learned from the $25-million research project. Federal funding for the project requires the partnership to ultimately disclose its results, with data releases beginning later this year. The lag time rewards companies that supported the project with a long first look. Cause and Effect? The completion engineers in the room those two mornings likely left wanting more. With one exception, the talks avoided mentions of the ultimate measure of what works—production. Instead, they challenged widely held mental images of fracturing. For one, fracture height is overrated. While microseismic testing indicated that fractures grew up about a 1,000 ft, the height of the propped fractures—the fractures most likely to produce oil and gas—was about 30 ft. Proppant distribution was sporadic. While there were thick fractures full of sand inside, a paper describing fracturing (URTeC 2902624) said that only three of them were found among hundreds of propped fractures. And all of those were found in the upper Wolfcamp. While the fractured lateral in the middle Wolfcamp was further from the slant well—135 ft vs. 90 ft from the nearest stage—the middle Wolfcamp core has a lot more proppant than the upper Wolf-camp core (URTeC 2902364).

Non-pumping reactive wells filled with mixing nano and micro zero-valent iron for nitrate removal from groundwater: Vertical, horizontal, and slanted wells

Non-pumping reactive wells (NPRWs) filled by zero-valent iron (ZVI) can be utilized for the remediation of groundwater contamination of deep aquifers. The efficiency of NPRWs mainly depends on the hydraulic contact time (HCT) of the pollutant with the reactive materials, the extent of the well capture zone (Wcz), and the relative hydraulic conductivity of aquifer and reactive material (Kr). We investigated nitrate removal from groundwater using NPRWs filled by ZVI (in nano and micro scales) and examined the effect of NPRWs orientations (i.e. vertical, slanted, and horizontal) on HCT and Wcz. The dependence of HCT on Wcz for different Kr values was derived theoretically for a homogeneous and isotropic aquifer, and verified using particle tracking simulations performed using the semi-analytical particle tracking and pathlines model (PMPATH). Nine batch experiments were then performed to investigate the impact of mixed nano-ZVI, NZVI (0 to 2 g l−1) and micro-ZVI, MZVI (0 to 4 g l−1) on the nitrate removal rate (with initial NO3−=132 mg l−1). The NPRWs system was tested in a bench-scale sand medium (60 cm length × 40 cm width × 25 cm height) for three orientations of NPRWs (vertical, horizontal, and slanted with inclination angle of 45°). A mixture of nano/micro ZVI, was used, applying constant conditions of pore water velocity (0.024 mm s−1) and initial nitrate concentration (128 mg l−1) for five pore volumes. The results of the batch tests showed that mixing nano and micro Fe0 outperforms these individual materials in nitrate removal rates. The final products of nitrate degradation in both batch and bench-scale experiments were NO2−, NH4+, and N2(gas). The results of sand-box experiments indicated that the slanted NPRWs have a higher nitrate reduction rate (57%) in comparison with vertical (38%) and horizontal (41%) configurations. The results also demonstrated that three factors have pivotal roles in expected HCT and Wcz, namely the contrast between the hydraulic conductivity of aquifer and reactive materials within the wells, the mass of Fe0 in the NPRWs, and the orientation of NPRWs adopted. A trade-off between these factors should be considered to increase the efficiency of remediation using the NPRWs system.

Stability and Vibrations of a Rotating Drill String in a Horizontal Wellbore

In view of the development of new technologies for the production of hydrocarbon fuels from shale rocks, increasing attention in the oil and gas industry is given to the problems of drilling slant and horizontal wells. The specific character of the processes of drilling such wells is that they are strongly acted upon by the forces of contact and frictional interaction between the drill string surface and the borehole wall, which arise in such cases. This paper formulates a problem of the bifurcation buckling and small bending vibrations of a rotating drill string lying in a horizontal wellbore. With allowance for friction forces and additional constraints, differential equations have been derived, for which solutions of eigenvalue problems of free vibrations of drill strings of finite and unlimited length have been constructed.

EFFECT OF DISCRETIZATION ON CALCULATION OF SLANT WELL PRODUCTIVITY INDEX IN NUMERICAL RESERVOIR SIMULATION

Slant well is a non-vertical form of wells used typically for extracting oil and gas resources that cannot be accessed through traditional vertical well drilling. Deviation in these wells results in the geometric skin factor, which has a negative value and increases the productivity index. Various analytical/semi-analytical equations estimate the geometric skin factor for the slant well for slightly compressible fluids. This study attempts to show that the productivity calculated by numerical simulation for the slant well in a single-phase (oil/gas) reservoir is sensitive to grid resolution. For this purpose, first, a slant well is defined within a local grid refinement (“LGR”) system. Afterwards, the slant skin factor is calculated for cases having different LGR resolution for a constant degree of inclination to find a reasonable LGR system. Then, the applicability of this optimum LGR for all deviation angles with comparison with analytical model is evaluated. This evaluation shows that optimum LGR is particular for each well deviation angle. Although some of the analytical/semi analytical models are developed for slightly compressible fluids, these models also are applicable for compressible fluids (i.e. dry gas). Furthermore, the calculated skin for the slant well in numerical simulation for optimum LGR is not sensitive to production rate or oil viscosity.