Placement Of Horizontal Wells Research Articles

PROSPECTS FOR INFILL DRILLING OF WELLS AT A LATE STAGE OF DEVELOPMENT ON THE EXAMPLE OF THE BS10 OBJECT OF THE MAMONTOVSKOYE FIELD

The article is devoted to the issue of optimizing the development system and increasing the efficiency of reserve production at the late stage of development of the BS10 object of the Mamontovskoye field and the formation of a strategy for its additional development. The results of the analysis of actual data from drilling horizontal wells and sidetracks made it possible to identify the most significant criteria for determining reserve localization zones for the purpose of placing new wells. The main factors for the effective placement of horizontal wells include: local dome uplifts, clinoform boundaries — zones where clinoforms pinch out, edge zones — zones with a lack of stock that require further exploration, distance from the formation pressure maintenance system — away from existing injection wells and with high accumulated injection , dissected zones, «pinched undeveloped reserves» — between injection rows, areas with long-term downtime of both injection and production wells — effects of reserve relaxation. The actual results of studies of core material and carbon-oxygen logging indicate the presence of relaxation processes in the formations of the BS10 object and the localization of oil pillars in the top part of the formation, which is further confirmed by hydrodynamic modeling. One of the key factors for planning the most effective measures is to take into account the effects of segregation and relaxation of stocks. The results of the implementation of infill horizontal drilling confirmed the high efficiency in areas of localization of current recoverable reserves in order to increase the rate of their production and achieve the approved values of oil recovery factors, the correct choice of the development strategy for the object at the current stage. The proposed methodological approach has shown high efficiency in searching for potential sites for drilling infill wells.

Prediction of Longitudinal Superimposed “Sweet Spot” of Tight Gas Reservoir: A Case Study of Block G, Canada

In this paper, taking Block G in Canada as an example, combined with the data of the working area, the Pearson–MIC comprehensive evaluation method was adopted to optimize the key parameters of productivity. Based on the analytic hierarchy process, the weight of each parameter was calculated, the grade of evaluation index of the “sweet spot” was divided, the standard of the sweet spot was established, and the distribution of the superimposed sweet spot was finally depicted. The results show that lateral length, number of stages, volume of fluid, and amount of proppant are the key engineering parameters of horizontal well, and lateral length is an independent key engineering parameter. The cumulative gas production in the first two years was normalized on the lateral length to eliminate the engineering influence, and the total organic carbon (TOC) was finally determined as the key geological parameter, whereas porosity and water saturation were the secondary key parameters. The area of Type I sweet spots accounts for 24.2% in the Series Upper and 23.1% in the Series Lower. This study proposed a new sweet spot prediction idea based on the influence of geological factors on productivity, and its results also laid a foundation for the subsequent placement of horizontal wells in Block G.

Bowland Shale well placement strategy – Part 2: Fracture simulations using a 3D geomechanical model and implications for stratigraphic and spatial horizontal well locations

Hydraulic fracture modelling is a key component of a shale reservoir well placement strategy as it provides an indication of the typical lengths and heights of stimulated fractures and of the changes to the stress environment in which these are propagating. However, spatial and stratigraphic variations in the stress and geomechanical properties of shales make accurate modelling a challenging task. For the UK Bowland Shale, stacked horizontal wells targeting multiple stratigraphic intervals could be used to avoid large offset faults in a geologically complex area. However, it is not known how these intervals may respond to hydraulic fracturing and predicting the height and length of hydraulic fractures is necessary in order to assess the likelihood of vertical fracture interference across landing zones or propagation towards major faults. In the case of the former, intervals of high effective stress may be key to containing fractures within their desired target. Using a planar hydraulic fracture simulator, and a 3D geomechanical model incorporating dipping stratigraphy, the issue of predicting hydraulic fracture geometry in the Bowland Shale was assessed through a series of modelling exercises using well Preese Hall-1 and horizontal pseudo-wells. When pre-defined landing zones were targeted, narrow and long transverse fractures around 1 km from the well were simulated. When the simulation design mimicked perforation clusters placed at 12 m intervals along horizontal pseudo-wells, the effects of stress shadowing were acute and resulted in irregular fracture geometries. Furthermore, high effective stress intervals performed efficiently as barriers to vertical hydraulic fracture propagation, reinforcing the feasibility of using stacked production for the Bowland Shale. The modelling results were then used to discuss the possible placement of horizontal wells in a mapped, 100 km2 region around well Preese Hall-1, where up to 13 sites could be positioned, with a horizontal well length of around 1.5 km. Finally, by drawing on a well-established analogue for the Bowland Shale, it was estimated that up to 195 Bcf of gas could be produced from the 13 locations in the area if three stratigraphic intervals are produced from one location.

Integrated shale-gas reservoir characterization: A case study incorporating multicomponent seismic data

The objective of this case study is to predict geologic properties of a shale reservoir interval to guide production and completion planning for successful development of the reservoir. The conditioning, analysis, and blending of the converted-wave (PS) seismic data into a quantitative interpretation (QI) workflow are described in detail, illustrating the successful integration of geologic information and multiple seismic attributes. A multicomponent 3D seismic survey, several wells with dipole sonic logs, and a multicomponent (3C) 3D vertical seismic profile are available for the study. For comparisons of the incremental value of PS data, the QI workflow is completed entirely using only PP data and then modified and redone to incorporate information from the PS data. Predictions of the geologic properties for both workflows are assessed for accuracy against the existing well log and core evidence. Determining reservoir properties of the shale units of interest is important to the successful placement of horizontal wells for efficient multistage hydraulic fracturing and maximum gas production. Although conventional interpretation of conventional seismic data can only provide reservoir geometry, the quantitative analysis of prestack multicomponent data in this study reveals detailed distinctions between reservoir units and relative measures of porosity and brittleness bulk properties within each unit. Using all of the elastic properties derived from the seismic data analysis allowed for the classification of lithological units, which were, in turn, subclassified based on unit-specific reservoir properties. The upper reservoir units (Muskwa and Otter Park) were shown to have more variability in brittleness than the lower reservoir unit (Evie). Validation at a reliable well control confirmed these distinctive units and properties to be very high resolution and accurate, particularly when the PS data were incorporated into the workflow. The results of this method of analysis provided significantly more useful information for appraisal and development decisions than conventional seismic data interpretation alone.

Shale gas reservoir characterization and sweet spot prediction in China

An integrated study of the well Zhao-104 and surrounding wide-azimuth 3D seismic data volume within the shale gas reservoir in South China has been conducted with the objective of generating shale formation properties related to fracture orientation and intensity in the area and deriving such reservoir rock properties as data quality allows. Well data, structural seismic information and prestack inversion products were combined in an integrated interpretation. Seismic gather conditioning improved seismic data quality prior to pre-stack inversion by improving signal/noise ratio, removing NMO stretch and aligning reflection events. Velocities from residual moveout (RMO) analysis on individual sectors were used as input to detection of fracture orientation and anisotropy. Fracture strike and P-wave anisotropy were calculated using the RMO updated sector velocity fields in elliptical velocity inversion, while inversion for P and S impedance and derivative attributes produced volumes that relate to rock properties such as brittleness and rigidity that are likely to impact fracturing. Measured logging curves were edited and missing curves estimated for the entire wellbore for geophysical purposes. Porosity, mineralogy and saturation were also estimated and elastic attributes were examined in crossplot space to find discrimination in properties of interest. Matrix modelling and synthetic seismograms were studied in order to understand likely seismic signatures and AVA behaviour. A set of post-stack volumetric attributes that are indicative of the presence of faults and fractures were derived and fed into an unsupervised neural network to perform fracture facies classification. In addition, seismically resolvable faults and discontinuities were automatically generated from fault sensitive attributes. At the end, information from all parts of the project were combined to assess structural characteristics and identify areas of high fracturing and stress direction that are important for the placement of horizontal wells and likely high total organic content (TOC) zones, necessary as a source of hydrocarbons or ‘sweet spot’.

Application of 3D seismic attributes to optimize the placement of horizontal wells within a tight gas sand reservoir, Ordos Basin, China

The Lower Permian Xiashihezi Formation in the Ordos Basin, China, is a quartz-sandstone reservoir with low porosity and low permeability. We have acquired 3D seismic data and well data from 18 vertical and four horizontal wells to indicate the potential of seismic attribute analyses in locating seismic sweet spots for lateral placement of horizontal wells. Using the analytic wavelet transform with a Morse wavelet, the integration of high tuning spectral components, high sweetness and high spectral attenuation helped us to estimate the distribution of gas-bearing tight sands in the Xiashihezi Formation. Our results revealed that the principal target of horizontal drilling and production was gas-bearing massive point bars in the braided river delta setting of the Ordos Basin. The integrated workflow of the seismic attribute analysis contributes to the optimal horizontal well planning by mining and exposing critical geological information of a tight gas sand reservoir from within 3D seismic data.

Efficient optimization framework for integrated placement of horizontal wells and hydraulic fracture stages in unconventional gas reservoirs

Rapid advances in horizontal well drilling and hydraulic fracturing have made these technologies standard development strategies in unconventional gas reservoirs. Further improvements in these practices by means of numerical optimization of wellbore locations and hydraulic fracture (HF) stages spacing can enhance shale gas reserves and increase revenue from the unconventional projects. In order to solve these two challenges simultaneously as an integrated optimization problem, an automated framework for placement of horizontal wellbores and HF stages is developed and tested in this paper. Coupled with expert knowledge and engineering judgment, this workflow allows to produce unconventional assets economically.This paper presents specifics of our novel optimization framework that improves the design and placement of HF stages in shale gas reservoirs and increases production and the net present value (NPV) of the projects by judicious application of numerical optimization algorithms. In particular, we test several gradient-based and gradient-free methods, namely, simultaneous perturbation stochastic approximation (SPSA), Genetic Algorithm (GA), and covariance matrix adaptation evolution strategy (CMA-ES). Application of these optimization strategies to a suite of test cases illustrates that it is not necessary to assume even spacing between HF stages because the algorithms have a capability to optimize HF stages spacing in homogeneous and heterogeneous geologic systems.

Innovative Geosteering Technology in Multilateral Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24002, ’Innovative Geosteering Technology Used in Drilling Smart Multilateral Wells, Kuwait,’ by T. El Gezeery, A. Aziz Ismael, K. Al-Anezi, G.S. Padhy, Fawaz Al Saqran, A. Abdul-Latif, and J. Silambuchelvan, Kuwait Oil Company, and J. Estarabadi and G. Ferroni, Geolog International, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission. The Burgan reservoir in Kuwait has the potential for premature water breakthrough, leaving behind bypassed zones of oil. The placement and completion of horizontal wells in such reservoirs is a challenge necessitating a collaborative approach from petroleum geoscience, reservoir engineering, and petroleum engineering. This paper describes placement of horizontal wells in this kind of heterogeneous reservoir through an integrated approach. Introduction The Minagish field was discovered in 1959 and is located in the southwestern part of Kuwait. It contains several reservoir intervals in its stratigraphic column, varying from Early Jurassic to Late Cretaceous. The field is situated 12 km northwest from the West Umm Gudair field (Fig. 1). The field has been penetrated by more than 180 wells. The field structure of the Burgan formation is a closed elongated asymmetrical anticline oriented in a north/south direction. The top of the Burgan structure is located at approximately 5,500-ft true vertical depth (TVD) minus the elevation above mean sea level of the depth reference point of the well. Regional Geology. The Burgan formation consists of a lower braided river system with stacked sand bodies. The sediment ranges from fine to medium grain sizes, and the porosities are high enough for lateral migration. On top of the upper Burgan channels, the sediments are generally finer but still retain a fluvial character. The amount of shale is higher. The marsh and tidal sediments, which consist of fine sands, silty sands, and sandy silts, seem to be of lower connectivity for vertical migration. The porosity is relatively low (between 15 and 18%), and the minimum of the measured permeability is close to 1 md for these layers. It seems that these shaly sediments can act as permeability barriers for vertical migration, but oil is observed in all channels and has been able to reach the reservoirs. This complex channel geometry makes these reservoirs the most challenging clastic reservoirs in the Minagish field.

Integrating Well and Seismic Data for Characterisation of Shale Plays

Shale plays have revolutionised the oil and gas industry in North America and exploitation of these kinds of plays is steadily gathering pace in other parts of the world. Because hydrocarbon bearing shales usually have insufficient permeability to allow significant flow to a well, production from these unconventional reservoirs comes with unique challenges. Optimizing recoverable reserves from shales requires strategic placement of horizontal wells: placing the well in the best areas, drilling the lateral in the proper direction and keeping the lateral portion of the wellbore in the optimum layer. It further requires production stimulation by hydraulic fracturing (fracking) of the rocks to connect the natural fractures with induced near-well fractures. In this paper, we present a methodology to identify these optimum areas and layers in the shales using a seismic characterisation workflow where well and seismic data are rigorously integrated. The first part of the approach is well data analysis to extract petrophysical, rock physics and mechanical information. Shale formations have a complex mineralogy requiring a sophisticated petrophysical analysis. Then a seismic inversion is performed to predict rock properties, which characterise the shale reservoirs and importantly allow us to predict how the rocks will respond to fracking. The final part of the methodology is an interpretation of multiple rock property models in terms of defined shale facies. A Bayesian approach was adopted to generate shale facies models that describe the thickness and complex architecture of shale reservoirs. These facies models can be used to significantly reduce the risk of poorly performing wells and improve asset performance.

Developing Flank Areas in a Giant Carbonate Field With Horizontal-Well Placement

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 161591, ’Development of Flank Areas in a Giant Carbonate Field With Optimal Placement of Horizontal Wells,’ by Sameer Khan, SPE, Ali Al-Shabeeb, Zankar Jani, Yousef Azoug, Nguyen Minh, and Harshad Patel, SPE, Zakum Development Company, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Successful development of flank areas depends on accurate reservoir characterization—in particular, water-saturation distribution—in addition to the optimal areal and vertical placement of wells. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact; the proper spacing and vertical placement of these wells are critical. To test the initial concept in the field, two existing producers were converted into injectors, and pressures were monitored at the offset producers. Introduction The subject oil field is one of the world’s largest offshore carbonate reservoirs and has a production life in excess of 100 years. The field was historically developed with wellhead tower platforms made of steel structures and a combination of vertical and 1-km-long horizontal wells in a five-spot pattern. A new development plan was proposed in 2008 that deployed artificial islands as drilling centers and used extended-reach- drilling technology. In addition, well counts were significantly reduced by deploying longer (3-km) horizontal laterals, referred to as maximum-reservoir-contact (MRC) wells. The development plan comprised both surface and subsurface components, which were effectively integrated to provide maximum flexibility in terms of development options as well as handling of reservoir uncertainties. Because the aquifer support for the subject field is weak, the development consists of a waterflood with line drive to be followed later by gas injection. This island-based plan was approved by shareholders in 2008, and implementation began soon thereafter. The development plan includes a comprehensive subsurface development scheme based on the available data and prediction tools. Development-plan optimization soon began as more data were being acquired and new reservoir models were built. This work is focused on development-plan optimization of two large flank areas of the largest reservoir in the subject field (south and east flanks in Fig. 1). These flank areas contain very large capillary transition zones that, although only a few hundred feet high, extend to several kilometers areally because of very low reservoir dip (1 to 2°) in a 150-ft-thick reservoir. Therefore, appropriate areal and layer placement of MRC wells in flank areas is a critical task that requires careful attention.

Delineation of a sandstone-filled incised valley in the Lower Cretaceous Dina-Cummings interval: implications for development of the Winter Pool, west-central Saskatchewan

Abstract Major heavy oil deposits are present in Lower Cretaceous strata of west-central Saskatchewan. The Winter Heavy Oil Pool (approximately 566 044 mmbl) consists of bitumen-rich sands from the Aptian–Albian Dina and Cummings members of the Mannville Group. This succession unconformably overlies Paleozoic carbonates and is conformably overlain by the Lloydminster Member. Lower Cretaceous deposition in the Winter area was influenced by topography on the regional sub-Cretaceous unconformity, including the Unity uplands south of the study area and major paleovalleys opening to the northwest. The overall depositional framework consists of a lowstand and transgressive fluvial sandstone deposit (Dina Member) that evolved into a brackish embayment system (Cummings Member). Upon sea level fall, a valley was incised into the mudstone-dominated marginal marine deposits, which filled with sandstone during a subsequent sea-level rise (Cummings Member). Exploitable heavy oil reservoirs are contained within these incised valley sandstone beds. Further transgression led to a rising water table with widespread deposition of an organic-rich shale and coal followed by marine shale of the Lloydminster Member. The new depositional model for the area should lead to more optimal placement of horizontal wells in the reservoir, which is vital to continued bitumen extraction from the Winter Pool.

Geological steering of horizontal wells in chalk reservoirs Examples from the Danish North Sea

The reservoir position of horizontal wells drilled in low permeability chalk reservoirs is of vital importance for the well performance. Accurate placement of horizontal wells drilled in the low permeability chalk fields in the Danish North Sea is being achieved by rigorous evaluation of geological information acquired during drilling. The tools which are being utilized for geological steering of horizontal wells comprise: High resolution biostratigraphy, Logging While Drilling, shows evaluation and analysis of 3D seismic data. Examples from the Dan, Kraka, Skjold and Tyra fields illustrate the current applications of geological steering in chalk reservoirs.