The coal-seam gas (CSG) industry has long been considered as a high volume, low cost market. As the industry has matured, the selective application of high-tier technologies has realized a step change in performance and real-time formation evaluation results. We investigated whether a high-tier LWD multi-function service could provide a suite of quantitative real-time measurements in several deviated wells. The key objective was to reduce the amount of non-productive rig time spent waiting for memory data in order to confirm the completion design. Significant savings in rig time could be realised if reliable, high-quality real-time data enabled the early identification of coal seams and permeable aquifers such that the swellable packer and slotted liner completion design could be completed without the need for final memory logs.
The area of interest is characterized by thin Jurassic coal seams rather than thick Permian seams. It was critical to accurately identify thin coal beds in real-time whilst maintaining a high rate of penetration (ROP). Low-resolution data would result in poor completion design, underestimation of net coal reserves, and sub-optimal static models. Measuring coal thickness and properties can be difficult due to the fundamental differences between the formation evaluation measurements and their relative axial resolutions. The presence of thin coals can further complicate the interpretation. Another challenge was to optimize the real-time data transmission to prevent any limitation on the key directional drilling data parameters.
Conventional LWD logs (gamma ray, nuclear, and resistivity measurements) provide formation evaluation information while drilling. The selection of a rotary steerable system (RSS) was critical as it ensured directional control and avoided any sliding intervals over key aquifers and coal zones, thereby ensuring optimal LWD acquisition. Advanced formation evaluation options of the LWD data also included using dual-pass resistivity inversions for Rt/Rxo to determine the invasion profile in a permeable aquifer zone above the main coal-producing reservoir. Having this information in real-time was critical in guiding well-specific competition decisions. Induction and laterolog-type resistivity tools were run on one well to quantify differences in the measurements and to determine the best resistivity acquisition tool for CSG wells drilled with saline muds in freshwater formations.
The results showed that high-tier LWD technologies provide multiple benefits in CSG wells. The project was executed with all directional and logging objectives achieved. Quantitative real-time data was critical for completion decisions including ECP placement together with swellable packer and slotted liner designs. This resulted in significant cost savings which are important to major CSG developments operating within a low-cost operating model. LWD memory data provided a rich suite of additional measurements to complement the real-time data. Memory data was used for advanced reservoir analysis with industry-unique measurements.
Abstract With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery. Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity. Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.
Serry, Amr (ADNOC Offshore) | Al-Hassani, Sultan (ADNOC Offshore) | Budebes, Sultan (ADNOC Offshore) | AbouJmeih, Hassan (ADNOC Offshore) | Kaouche, Salim (ADNOC Offshore) | Aki, Ahmet (Halliburton) | Vican, Kresimir (Halliburton) | Essam, Ramy (Halliburton) | Lee, Jonathan (Halliburton)
Abstract This case study demonstrates the role of nuclear magnetic resonance (NMR) T1 spectra, as used to drill complex undeveloped carbonate formations offshore Abu Dhabi. The scope of this project exceeds the traditional porosity-permeability approach to exploit the wealth of information about the rock texture, pore size distribution, flow units and a new methodology of NMR T1 data processing. Evaluation of pore size distributions based on T1 vs. T2 spectra is addressed in two case study wells; one using a 6 ¾-in., and the other a 4 ¾-in. mandrel size for the first time in UAE. Finally, other log-derived permeabilities are presented, together with high-resolution microresistivity image interpretation and production log results in an integrated approach for improved understanding of the petrophysical character of these undeveloped units. NMR T1 measurements are utilized for the first time in the lateral sections as part of a bottomhole assembly (BHA) consisting of a rotary steerable system (RSS), and logging-while-drilling (LWD) sensors, including high-resolution microresistivity imaging, laterolog and azimuthal electromagnetic wave resistivities, thermal neutron porosity, azimuthal density, azimuthal multipole acoustic, ultrasonic caliper and near-bit azimuthal gamma ray. During NMR T1 measurements, the spin relaxation time carries information about the liquid-solid surface relaxation and bulk-fluid relaxation, hence, it is neither affected by rock internal magnetic field gradients nor by differences in fluid diffusivity. Also, T1 logging measurements are influenced by instrument artefacts to a much lesser extent than T2 results, having several advantages over T2, especially regarding polarization and tool motion while drilling. The real-time availability of NMR sourceless porosity measurements significantly improved drilling decisions to place the two case history wells into favourable zones and NMR T1 permeabilities were derived together with acoustic and high-resolution microresistivity image-based permeabilities which were then correlated to production logs. The results indicate that T1 measurements are an effective, practical solution for rock quality evaluation using LWD real-time datasets free from BHA motion and fluid diffusion effects. Comparisons of T1 and T2 logs show that T1 yields equivalent formation evaluation answers, despite its sparser nature. The T1 spectra facilitated improved pore size distribution, permeability estimation and marking of the hydraulic flow units in the heterogeneous, undeveloped Upper Jurassic reservoir units, paving the way for the consideration of T1 logging as a viable, and in some cases superior alternative to T2 logging. This paper presents the multidisciplinary approach used to benchmark and optimize the future field development program.
Davis, Graham (Premier Oil) | Newbould, Rob (Premier Oil) | Lopez, Aldo (Premier Oil) | Hadibeik, Hamid (Halliburton) | Guevara, Zunerge (Halliburton) | Engelman, Bob (Halliburton) | Balliet, Ron (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Imrie, Andrew (Halliburton)
The oil and gas potential of the basins surrounding the Falkland Islands has attracted exploration drilling that resulted in discovering the Sea Lion Field in the North Falkland Basin in May 2010. Recent exploration drilling has resulted in new oil discoveries to the south of the Sea Lion Complex that has not only confirmed the area as a significant hydrocarbon province but has also enhanced the likelihood of future commercial development of resources. Primary oil targets are stacked and amalgamated deepwater lacustrine turbidite fans comprising multiple lobes. In exploration and appraisal wells, porosity characterization, permeability assessment, pressure measurements, and hydrocarbon fluid identification are essential input data for robust reservoir characterizations and resource estimations.
A comprehensive suite of advanced logging measurements, in addition to conventional log measurements, have been used to facilitate data analysis and calibration to laboratory core measurements. The pressure gradients and fluid samples obtained from formation testing when combined with the wireline log measurements are fundamental when determining the thickness, quality, and connectivity of hydrocarbon zones, which, in turn, impact the commercial evaluation of the well. In these remote offshore basins where rig costs are high and the ability to focus data acquisition in specific zones of interest and minimize logging time whilst identifying and reacting early in real time to data points that lie off the expected trends can add significant value to the operating company.
Formation evaluation challenges include hydrocarbon identification and resolving fluid contact uncertainties. In addition, establishing whether there are any baffles or barriers in the system or significantly varying reservoir properties as a consequence of facies changes has the potential to complicate the evaluation in respect to permeability characterization and volume estimation.
A method of facies classification using a combination of resistivity-based borehole imaging data and nuclear magnetic resonance (NMR) data is outlined in this paper. This method, when combined with conventional log data, has exhibited encouraging results in terms of identifying lithofacies and determining a rock quality index (RQI). The mud logs and gamma ray logs were interpreted with the borehole image logs in these turbidite reservoirs, which resulted in identifying four distinct depositional lithofacies. These lithofacies were integrated with the free fluid index (FFI) to bulk volume irreducible (BVI) ratio determined from the NMR data. The FFI to BVI ratio was used as an index for RQI classification, which was then subsequently used to optimize formation pressure testing and sampling points.
The contribution and importance of lithofacies identification is typically ignored when optimizing formation pressure depths and interpreting the results. The methodology presented in this paper uses an integrated workflow jointly developed by the operator and service company that allows detailed reservoir evaluation in the zones of interest and real-time adjustments to optimize the data acquisition programme that potentially enables rig-time savings and, consequently, reduces overall formation evaluation costs.
Serry, A. M. (Abu Dhabi Marine Operating Company) | Kaouche, S.. (Abu Dhabi Marine Operating Company) | AbouJmeih, H.. (Abu Dhabi Marine Operating Company) | Smith, S.. (Baker Hughes) | Elarouci, F.. (Baker Hughes) | Khairy, H.. (Baker Hughes)
Abstract The objective of this paper is focused on presenting and highlighting the results of the first successful reservoir fluid characterization and sampling attempt in offshore Abu Dhabi and the added values to the assets operating in the highly heterogeneous Jurassic carbonate reservoirs with unknown formation water salinity values. The original formation water has a unique high salinity that got mixed overtime with the fresher injection water, so that the open hole log interpretation using Archie water saturation model becomes highly uncertain. Exaggerated oil saturations could be computed within the water zones around the oil-water contact. In addition to measuring the fluid mobility, the formation testers are being run to confirm the fluid type present in the reservoir by using pressure gradient plot or by fluid identification and sampling stations. The increasing cost and rig time optimization demands inspired the team to utilize the emerging formation sampling and testing while drilling at the first time in offshore Abu Dhabi to replace the conventional wireline/ drill pipe conveyed formation testers. This application proved to be an added value to gather the required reservoir data in a mature challenging field reducing the operational time, cost and associated risks. A water injection well is drilled across a highly heterogeneous, Jurassic carbonate reservoir offshore Abu Dhabi. A deviated pilot hole was drilled for formation evaluation and reservoir fluid assessment, and the plan was to continue with a horizontal drain into one of the sub-reservoirs (swept area) if confirmed water bearing. The logging while drilling formation sampling and pressure testing tool was run combined with the conventional open hole logs to minimize the formation exposure time, real time down-hole fluid analysis started very shortly after drilling to the bottom of the target reservoir, based on the rush open hole log interpretation. Different sensors, with different physics (namely; fluid viscosity, density, sound speed, optical refractive index, temperature, fluid mobility and compressibility) were used to characterize the fluid during the pump-out stations. Due to the minimized mud filtrate invasion effects, this operational sequence allowed the gathering of conclusive formation fluid samples with less pumping time and volume. This paper shows the operational planning, design and execution outlines, discusses the benefits of acquiring clean formation samples right after drilling compared to those acquired with the conventional conveyance techniques, and indicates the drawbacks and the limitations of this technology together with any window of improvement.
Summary When drilling in an arid region through heavily fractured formations, it can be very challenging to manage drilling-fluid losses and at the same time maintain a downhole-pressure gradient that is compatible with the very-low geopressure gradient windows that are typically encountered in those drilling conditions. Nitrogen-enriched drilling muds may provide a good solution to both problems; however, the properties—such as density, rheology, specific-heat capacity, and thermal conductivity—of this type of drilling fluid are highly dependent on temperature and pressure, and in most cases those characteristics cannot be measured in situ, making it difficult to estimate the actual downhole-pressure conditions. The approach described in this paper consists of the reconstruction of the drilling-fluid-mix properties from the characteristics of its components and the incorporation of the resulting pressure- and temperature-dependent constitutive laws into a real-time multiphase- and multicomponent-drilling hydraulic model to estimate the downhole pressures along the drillstring and borehole as a function of the drilling parameters. Because of the uncertainty of some of the characteristics of the components of the drilling fluid as well as their actual proportion in the mix, the modeled values are only valid within a certain accuracy. Stochastic simulations are made during the estimation of the downhole pressures to ascertain the precision of the calculations. As a consequence, by comparing the obtained interval of confidence on the estimations with actual measurements, it is possible to evaluate whether the drilling conditions are normal or deteriorating. The validity and performance of the derived fluid-model extension are tested by use of a real-time data set recorded during the drilling of a well in the Erbril area of the Kurdish region of Iraq, by use of the wellsite information transfer standard markup language drilling-data-exchange protocol. The model results are reviewed and compared with the actual measurements recorded during the drilling operations. The potential sources of limitation, discrepancy, or error between the modeled and observed well and fluid behavior are discussed, along with potential explanations for the observed wellbore physics seen in the recorded-data feed.
Kerkar, Prasad B. (Shell International Exploration and Production Inc.) | Hareland, Geir (Oklahoma State University) | Fonseca, Ernesto R. (Shell International Exploration and Production Inc.) | Hackbarth, Claudia J. (Shell International Exploration and Production Inc.)
Abstract In unconventional gas and tight oil plays, knowledge of the in situ rock mechanical profiles of the reservoir interval is critical in planning horizontal well trajectories and landing zones, placement of perforation clusters along the lateral, and optimal hydraulic fracture stimulation design. In current practice, vertical pilot holes and/or the laterals are logged after drilling, and the sonic and neutron log results are interpreted along with mechanical rock properties measured in the laboratory on core material. However, coring, logging, and core analyses are expensive and time consuming. In addition, as they are typically only performed in a few wells that are assumed to be representative, there is considerable uncertainty in extrapolating results across wide areas with known variability in stratigraphy, faults, thicknesses, hydrocarbon saturations, etc. This paper reports a method for estimating mechanical rock properties and in situ rock mechanical profiles in every well in a development, based on calibration from initial rock core analyses plus drilling data that is routinely acquired. Wellbore friction analysis was coupled with a torque and drag model to estimate in situ unconfined compressive strength (UCS) and Young's modulus (YM) profiles. The key process steps include: Calculate the weight and wellbore friction force of each element of the drill string from bottom to the surface; Adjust the hook load (HL) by subtracting the weight of the hook and entire drill string; Iteratively compute the friction coefficient to match calculated and observed HL; Estimate downhole weight-on-bit (DWOB) by applying a stand pipe pressure correction to the calculated HL and considering potential sliding and abrasiveness; Use a rate of penetration (ROP) model developed for polycrystalline diamond compact (PDC) drill bits considering a force balance between a drill bit geometry and formation and a wear function depending upon the formation abrasiveness and bit hydraulics to compute confined compressive strength (CCS). The resulting CCS was correlated to UCS and YM using regression constants obtained from laboratory triaxial test data on whole core. Using examples from horizontal wells in a siltstone play in Alberta, Canada, this manuscript demonstrates a workflow to estimate rock strength from drilling data. The predicted UCS and YM values were compared with log data and potential uncertainties arising out of drilling data are discussed. Introduction In conventional and unconventional plays alike, a typical way to characterize the subsurface is to make measurements of the formation penetrated by the wellbore with logging tools that are either carried behind the drill bit (logging while drilling) or else run in the well after the drill string is removed (wireline or drill pipe-conveyed logging). Because this adds cost and risk, for unconventional gas or tight oil (UGTO) projects that may have hundreds to even thousands of producers, typically only early appraisal wells plus later, areally scattered wells are designed with extensive logging and laboratory core characterization programs. The assumption is that lateral variability and local heterogeneties are not great and that these data-rich penetrations sufficiently constrain the reservoir properties in the areas between them. In UGTO projects, good representations of the in situ stress profile and geomechanical rock properties are required to optimize the well trajectories and landing zones, placement of perforation clusters along the lateral, and hydraulic fracture stimulation design.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 159261, "Novel Design and Implementation of Kuwait's First Smart Multilateral Well With Inflow-Control Device and Inflow-Control Valve for Life-Cycle Reservoir Management in High-Mobility Reservoir, West Kuwait," by Om Prakash Das, Khalaf Al-Enezi, Muhammad Aslam, Taher El-Gezeeri, and Khalid Ziyab, SPE, Kuwait Oil Company; and Steven R. Fipke and Steven Ewens, Halliburton, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.
Kuwait’s first smart Level-4 multilateral well was completed in the Burgan reservoir by combining a Level-4 junction with stacked dual-lateral completion with a customized viscosity-independent inflow-control device (ICD), two customized inflow-control valves (ICVs), downhole gauges, a wide-operating-range electrical submersible pump (ESP), suitable wellheads, a tree, and integrated surface panels for real-time data monitoring. The smart multilateral well has assisted in addressing premature water breakthrough, has enhanced water-free oil production, and has facilitated uniform depletion, which results in improved hydrocarbon recovery.
The Minagish field in west Kuwait (Fig. 1) is a north/south-trending anticline with hydrocarbon contained in six major reservoirs (sandstone and carbonate) ranging in age from Early Jurassic to Late Cretaceous. The Burgan sandstone reservoir lies at the crest of the Minagish field.
The lower section of the Burgan sandstone reservoir consists of a braided river system with stacked-channel sand bodies that have very high horizontal and vertical permeability (on the order of a few darcies) and are associated with an underlying active aquifer. The combination of high oil viscosity, oil-wet reservoir characteristics, and very high water mobility associated with very high permeability and the presence of fault networks connected to the aquifer accelerates water movement inside the reservoir and results in premature water breakthrough in existing vertical and horizontal wells, despite maintaining highest standoff from the oil/water contact.
Smart-Multilateral-Well Architecture and Design
The smart-multilateral-well design was customized for ICD completion at the sandface for both the main-bore and upper-lateral intelligent completion including two ICVs, downhole gauges, feed-through packers, and a Level-4 cemented junction to provide fullbore access to the main bore and upper lateral. A schematic of the smart multilateral well is shown in Fig. 2.
ICD Selection and Design
The following objectives were considered for completion of the horizontal open-hole section of the main bore and upper lateral of the smart multilateral wells:
Ridley, K.. (Shell Exploration and Production Company) | Jurgens, M.. (Shell Exploration and Production Company) | Billa, R. J. (Shell Exploration and Production Company) | Mota, J. F. (Shell Exploration and Production Company)
Abstract In late 2010, Shell began an Eagle Ford appraisal program at Piloncillo Ranch in South Texas. These wells are 8,500’ – 9,500’ TVD horizontals, with an average total depth of 14,500’ MD. Their primary target is the Cretaceous Eagle Ford shale. The Shell leases are located in the gas-condensate window. Shell is currently running a five rig development program. Initially, reservoir pressures were thought to be in the 12.5 ppg range, but Diagnostic Fracture Injection Tests (DFITs) showed the actual pore pressure to be greater than or equal to 14 ppg. Initially, underbalanced drilling techniques were used to drill the 14-14.5 ppg formation with 11 ppg oil based mud. The Eagle Ford has no natural fractures in this area. As more wells were drilled, however, completion fracturing of offset wells began to cause well control problems, as induced fractures were encountered in horizontal sections during drilling. Initially, it was thought that additional casing strings would be required to deal with the higher pressures and flow capability of the 14-14.5 ppg fracture; however, through well control modeling and experience with underbalanced drilling in other tight gas environments, tripping and heavy pill spotting procedures were developed that allowed the wells to be drilled with the initial casing program. This paper will describe the development of fit for purpose well control techniques used to drill underbalanced horizontal wells in the Eagle Ford shale gas play. It will discuss how the characteristics of tight shale formations in horizontal wells resulted in a different approach to well control and tripping procedures. Several simple techniques for establishing an understanding of real time data have helped to make decisions in the field with current information: Institute a dual density system to stop reservoir flow and prevent up-hole losses Create a Horner Plot for distinguishing ballooning from reservoir flow if losses are experienced Create a mud weight vs. influx flow plot for predicting flow changes with mud weight Ascertain how the influx rate and location affect the time at which it would a take a well to unload to dry gas The paper will also describe the software modeling used to determine influx responses and the methodology developed around it. This methodology is applicable to other tight shale formations drilled horizontally and developed around the globe. These procedures can significantly reduce non-productive time and minimize serious well control events on horizontal shale wells when properly followed.
Poedjono, Benny (Schlumberger) | Beck, Nathan (Schlumberger) | Buchanan, Andrew (Eni Petroleum Co.) | Brink, Jason (Eni Petroleum Co.) | Longo, Joseph (Eni Petroleum Co.) | Finn, Carol A. (U.S. Geological Survey) | Worthington, E. William (U.S. Geological Survey)
Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Arctic and Extreme Environments Conference & Exhibition held in Moscow, Russia, 18-20 October 2011. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.