Toempromraj, Wararit (PTTEP) | Sangvaree, Thakerngchai (PTTEP) | Rattanarujikorn, Yudthanan (PTTEP) | Pahonpate, Chartchai (PTTEP) | Karantharath, Radhakrishnan (TGT Oilfield Services) | Aslanyan, Irina (TGT Oilfield Services) | Minakhmetova, Roza (TGT Oilfield Services) | Sungatullin, Lenar (TGT Oilfield Services)
Success towards waterflood optimization requires the accessibility of downhole contribution and injection, challenging on the conventional cased-hole multi-zone completion where contribution and injection are gathering through sliding sleeve. This paper will describe the success in defining flow profile behind tubing by utilizing Temperature and Spectral Noise Logging.
With response in frequency and noise power when fluid flowing through completion accessories, perforation tunnels and porous media, fluid entry points for producer and water departure point can be located by noise logging. Additionally, conventional temperature logging can usually define degree of intake and outflow along with change in fluid phase as a result of change in temperature. In combination of these implications, downhole flow contribution and injection profile can certainly be determined even though fluid moving in and out through production tubing and casing.
Regarding pilot field implemtation in Sirikit field, two multi-zone-completed candidates have been selected, operations were carried-out for producer and injector according to the programs individually designed including logging across perforation intervals and station stops for multi-rate flow, transient and shut-in periods. Longer well stabilization is necessary for injector. In addition to production/injection logging interpretation by incorporating pressure, temperature, density and spinner data, the temperature simulation model is generated to determine downhole flowing/injecting contribution with parameters acquired during logging, for example, pressure and temperature. The other reservoir and fluid properties, e.g. permeability, thickness, hydrocarbon saturation, skin, heat conductivity and capacity have been analog based on available data from neighboring areas. Therefore, the historical data on production and injection including nearby well performance may be crucial to define necessary input to the model. In association with the interpretation of noise logging which is utilized in locating contributing/injecting zones, the interpretation strongly relies on acquired temperature data and outputs of temperature simulation model to match with measured temperature profile. However, limitations have been documented when dealing with multi-phase flow, especially in low flow rate condition – considered 5 BPD as a threshold. Sensitivity run with associated paramenters in the interpretation can significantly reduce the number of uncertainties to match with measured temperature profile.
Temperature and Spectral Noise Logging to provide input to temperature model can definitely help accessing downhole injection profile for the injector by taking benefit of one phase injecting and having contrast between injecting fluid and geothermal temperatures. This application can significantly improve the waterflood performance and optimization particularly in high vertical heterogeneous reservoirs – thief zones can be identified and shut-off consequently. However, defining downhole contribution for low-rate oil wells producing from multi-layered depleted reservoirs especially in undersaturated condition is still a challenge.
Abbas, Ahmed K. (Iraq Drilling Company and Missouri University of Science and Technology, Rolla) | Flori, Ralph (Missouri University of Science and Technology, Rolla) | Alsaba, Mortadha (Australian College of Kuwait)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk.
ABSTRACT: Wellbore instability problems play major rule in the increasing of the non-productive time (NPT) during drilling processes. In most cases, this cost can be reduced by designing a suitable operational window using geomechanical models. Several wellbore instability problems have been encountered during drilling Nahr Umr formation in an oil field in southern Iraq. These problems are including, but not limited to, mechanical stuck, caving, and tight holes. Data from more than twenty wells (vertical and deviated wells) are investigated to reveal the major factors that control the instability problems and to design an optimum mud window. In the present work, a 1-D mechanical earth model (MEM) was constructed using numerous field data for Nahr Umr formation. Based on the offset well data, open hole wireline logging measurements (e.g., density logs, gamma ray (GR) logs, sonic logs, formation micro-imager (FMI) logs, porosity logs, resistivity logs, drilling records, and mud logs (master logs)) the magnitude and orientations of the in-situ principal stresses, pore pressure, and rock mechanical properties were estimated. The 1-D-MEM was verified and calibrated using all the available data (i.e., drilling observations, caliper logs, results of image data interpretation, repeated formation test (RFT), hydraulic fracturing, and laboratory rock mechanical properties, etc.) such that it robustly and accurately predicts shear failure around given wellbores. The generated model was then coupled with three failure criteria (i.e., Mohr-Coulomb, Mogi-Coulomb, and Modified Lade) to analyze the existing wellbore stability problems for wells with directional profiles and to determine the appropriate mud weight to drill a well in any desired direction. Our analysis shows that the majority of the wellbore instability problems are mainly caused by; rock failure around the wellbore due to high stresses and low rock strength, and inappropriate drilling practice.
Despite the modern advancements and the usage of new technology in the oil and gas industry, wellbore instability remains one of the most challenging aspects in terms of the cost to drill and complete a well. Eight billion dollars are spent each year due to wellbore instability problems (Peng, 2007), causing an increase in the drilling budget by 10% (Aadnoy, 2003). Therefore, wellbore stability is considered to be one of the major stages of well planning and has been studied extensively (Bell, 2003; Bradley, 1979; Ding, 2011; Zhang et al., 2003; Zhang et al., 2009; Gentzis et al., 2009; Alsubaih et al., 2017; Abbas et al., 2018).
ABSTRACT: Wellbore collapse as a result of severe borehole breakouts represents a major problem in many cases. In order to quantify the risk associated to wellbore collapse a reliable estimate of the collapse volume is necessary. In this study, a novel approach determining the depth/area/volume of collapse failure by using image processing approach is presented. Since image processing can be applied to any result set, the proposed approach is independent of any failure criterion (such as Mohr Coulomb, Mogi-Coulomb and Modified Lade criteria) and very versatile. For hydrocarbon fields where Mechanical Earth Modeling (MEM) approaches capable of predicting the spatial distribution of horizontal stresses exist, the presented image processing approach is utilized to generate an automated log of collapse volume while drilling. Based on this log, mud pressure adjustments can be undertaken while drilling a new well based on collapse volume. The main contribution of this work is the estimation of a real-time collapse volume log while drilling. It can help the drilling engineers in evaluating the mud weight effect on the hole cleaning efficiency to avoid stuck pipe problems. In addition, knowledge of the collapse volume provides better estimates on the required mud and cement volumes.
The obvious goal for drilling operators is to drill economical, safe, and stable wells by reducing non-productive time (NPT) due to wellbore stability problems such as borehole collapse and associated stuck pipe, and borehole breakdown and associated loss of circulation. A key issue for successful drilling operations in geomechanically challenging zones is considering all relevant factors including-formation strength properties, in-situ stresses, pore pressure, and applied pressure by the drilling mud. If collected, these data sets of rock strength and stress can be used to generate a Mechanical Earth Model (MEM; e.g., Abbas et al., 2018; Goodman and Connolly, 2007; Kristiansen, 2007; Gholami et al., 2014). Once the MEM is validated, it can be used to predict applications such as wellbore stability (Cheatham, 1984; Kaushik et al., 2016; Alkamil et al., 2017).
Abbas, Ahmed K. (Missouri University of science and technology) | Dahm, Haider H. (Misan University) | Flori, Ralph E. (Missouri University of science and technology) | Alsaba, Mortadha (Australian College of Kuwait)
ABSTRACT: Zubair Formation (Lower Cretaceous) is a regionally extended oil-producing sandstone sequence in Iraq, Kuwait, Syria, Iran, and Saudi Arabia. The Zubair oil reservoir has a significant potential to contribute to the petroleum supply in Iraq. The Knowledge of petrophysical and geomechanical properties of the Zubair sandstone formation is required to assure the success of future exploration and development of this reserves. Hence, a high consistency and quality of reservoir properties may significantly improve the economic revenues derivable from the reservoir. This paper presents series of experiments that were conducted to investigate petrophysical and mechanical properties of 40 plug samples retrieved from the Zubair reservoir in Southern Iraq. The measured petrophysical properties included porosity, grain density, bulk density, grain size, and permeability. The geomechanical properties included static and dynamic elastic parameters (Young’s modulus, bulk modulus, shear modulus, and Poisson’s ratio), rock strength parameters (uniaxial compressive strength, cohesion, and internal friction angle), tensile strength, and acoustic velocity (compressional and shear wave velocities). The findings of this study can be used in solving wellbore instability problems, preventing sand production, enhancing reservoir simulation studies, optimizing drilling processes, and designing fracturing operations across the Zubair reservoir.
Zubair sandstone is one of the most important oil reservoirs in Southern Iraq that its petrophysical and geomechanical characters are not well known. These properties play significant role in the exploration and development operations for the hydrocarbon reservoir (Abbas et al., 2018a). In the exploration phase, petrophysical and geomechanical properties are required in pore pressure prediction, hydrocarbon column height estimation, and assessment of fluid flow into wells (Najibi et al., 2017). For the drilling and field development, the geomechanical properties have significant impact on estimating the in-situ stresses in subsurface formations, optimizing the drilling process (selection of the bit type and drilling parameters), optimizing well trajectory placement, casing design, wellbore stability analysis, and development of geomechanical models to address the minimum required mud weight to drill a stable well (Zoback et al., 2003; Alsubaih et al., 2017; Abbas et al., 2018b). Furthermore, unexpected problems such as reservoir compaction and sand production (in sandstone reservoirs) may occur several years after the exploitation and lead to decrease in reservoir pressure and permeability. Subsequently, production rate drop and land subsidence occur in these reservoirs (Khamehchi and Reisi et al., 2015). Thus, it is essential to plan an optimum exploitation of the hydrocarbon resources using petrophysical and geomechanical properties to prevent and/or mitigate the occurrence of these problems. Moreover, hydraulic fracturing techniques while the wells development phase are some remediation activities to enhance oil recovery, which strongly requires the knowledge of petrophysical and geomechanical properties (Wang and Sharma, 2017). Hence, an accurate technique to estimate the petrophysical and geomechanical properties may significantly improve the economic revenues for the Zubair Reservoir. Laboratory tests are the most direct and reliable way of determining petrophysical and geomechanical properties. Typically, geomechanical properties (static properties) can be obtained by gently applying uniaxial or triaxial stresses on cylindrical plug samples until failure occurs.
ABSTRACT: Zubair formation consists of approximately 55% shale, which causes almost 90% of wellbore problems, due to shale instability. To solve this problem, it is necessary to understand the rock mechanical properties and the response of shale. However, little data is available related to shale sections due to the additional cost of acquiring and preparing shale samples. The main objective of this study is to measure the rock mechanical properties of shale samples retrieved from the Zubair Formation in Southern Iraq. Extensive testing, including a number of shale characterization and rock mechanical tests were conducted on well-preserved core samples from Zubair shale. The core samples characterization included the porosity, structure, texture, and mineralogy, using the free water content method, a scanning electron microscope image, a thin section photograph, and X-ray diffraction analysis. Consolidated undrained triaxial tests were conducted to determine the static rock mechanical properties. The measured rock mechanical properties gave a good indication of the strength and stability of the shale around the wellbore. Consequently, it can be used to solve shale instability problems, optimize drilling processes, seal integrity evaluation, and improve fracturing operations across the Zubair shale formation.
Shale instability is frequently reported as one of the most serious obstacles while drilling the Zubair shale formation in several oil fields in Southern Iraq (Abbas et al., 2018a). Shale instability problems, such as borehole collapse, tight hole, stuck pipe and logging tools, poor log quality, borehole enlargement, and poor primary cement jobs result in excessive operational costs and delays in drilling time. The knowledge of the mechanical properties of Zubair shale is of crucial importance for drilling process optimization, wellbore stability analysis, well trajectory optimization, and hydraulic fracturing design (Yuan et al., 2012; Guo et al., 2015; Li and Tang, 2016; Abbas et al., 2018b). Stjern et al. (2003) reported an average cost reduction close to 2.5 million USD for an average well through the knowledge of shale mechanical properties; given that the field had 50 more wells to be drilled, the total savings would have been in excess of 100 million USD. However, shale formations are not the main target of hydrocarbon exploration; consequently, shale samples from deep boreholes are almost never available for testing due to the extra cost related to coring operations in deep wellbores. Even if the core samples are taken from depths of interest, the shale cores may be further damaged by the action of the drill bit during coring operations and by subsequent improper preservation and sample preparation.
As a result, the life of a PDC bit is limited. In other words, a PDC bit can drill only a certain distance or footage. To extend the life of a PDC bit, more diamond volumes or more PDC cutters are used. One method is to use backup cutters that form a second cutting layer in addition to a first cutting layer formed by primary cutters. Figure 1a shows that, in conventional designs, backup cutters were located rotationally behind their primary cutters on the same blades. Field observations confirm that backup cutters in conventional designs remove much less formation compared with their primary cutters but do wear at the same level as their primary cutters. Figure 1b depicts a typical case in which a backup cutter has similar wear as its primary cutter. The backup cutters might not be used properly in conventional designs. Although some successful runs have been reported (e.g., Gonzales et al. 2011; Teasdale et al. 2013; King et al. 2015; Abdullah et al. 2016), bit performance might be improved further if the angular locations and the underexposure of backup cutters are optimized.
Estimation of core permeability as a function of well logging records is a pivotal task in reservoir characterization as it is affected by data sparseness, distinct scales, various sources, and lithology structures. In this paper, three specific dataset formats of a well logging and core measurements were considered for the core permeability modeling and prediction using the ordinary kriging and co-kriging interpolation algorithms. The dataset were used as complete dataset of multi-facies and two split datasets of shale- and sand-based measurements. More specifically, the ordinary kriging was first used to model the core permeability as a function of the well logging records only through constructing the variogram given the three mentioned dataset types. The same procedure was repeated by adopting the cross-variogram approach to model the core permeability as a primary factor along with core porosity as a secondary factor, both as a function of the well logging records. The well logging attributes, which were obtained from an oil well, include neutron porosity and water saturation given the well depth.
The cross-variogram was adopted to quantify the dissimilarity between known and unknown data for the co-kriging interpolation to provide linear coregionalization modeling of core permeability and porosity. The modeling and prediction accuracy of core permeability through the ordinary kriging and co-kriging algorithms were assessed by applying the leave-one-out cross validation in addition to the visual mismatch between predicted and observed core permeability. Results illustrated that co-kriging interpolation led to a more accurate permeability prediction than the ordinary kriging by achieving the highest adjusted R-square and the lowest root mean square error. The integrated workflow of ordinary kriging and co-kriging was applied on a dataset from an oil well in sandstone reservoir in the South Rumaila oil field, Southern Iraq.
Modeling accurate lithofacies and petrophysical properties is a crucial step in the reservoir characterization as it affects reservoir heterogeneity, fluid flow modeling, and history matching, especially in complex geological structures. In this paper, the multiple-point facies geostatistics (MPFG) and sequential gaussian simulation were integrated as an efficient workflow for lithofacies and petrophysical property modeling of a fluvial sand-rich depositional environment of Zubair formation in South Rumaila oil field, Southern Iraq. The lithofacies features of the upper sandstone member has three main lithotypes derived from the core data analysis of 20 wells: sand, shaly sand, and shale.
In the MPFG, the surface map of the fluvial depositional system of the upper sandstone reservoir in Zubair formation was created through a 2D user-defined training image. The training image body and channels were pointed to the three aforementioned lithofacies as an alternative to the variogram to create the 3D facies system. Then, the surface map was sampled and trained by neural networks to create the discrete template of 3D facies distribution pattern into the 3D grid construction. The resulted pattern represents a numerical geomodel that captures all the features of the fluvial depositional environment of the reservoir, which then was adopted for 3D lithofacies modeling.
The resulting MPFG-lithofacies model reflected a more reasonable facies architecture than the sequential indicator simulation by preserving the fluvial features of the geosystem. Many realizations were generated and cross-validated to determine the most appropriate lithofacies model, which was considered later for the permeability and porosity modeling by the sequential gaussian simulation. To attain history matching, the resulting MPFG and petrophysical model was upscaled and incorporated into the compositional reservoir flow simulation for history matching. A near-perfect and fast history matching with the least mismatch was obtained with respect to observed and calculated cumulative and rates of oil production and water injection for the entire field in addition to all producers and injectors within the whole production history. The results reflect how is efficient considering multiple-point statistics to reconstruct the complex geological features to capture reservoir heterogeneity and achieve fast history matching.
Abbas, Ahmed K. (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Al-Asadi, Yousif M. B. (Schlumberger) | Alsaba, Mortadha (Australian College of Kuwait) | Al-hamad, Nasser A. (Schlumberger)
Zubair oil reservoir has a significant potential to contribute to the petroleum supply in Iraq. Drilling highly-deviated wells is a commonly used approach to enhance the production in mature fields. Drilling these wells in the Zubair Formation has been a challenge due to severe wellbore instability issues. This study presents how integrated reservoir geomechanics was used for efficient well planning and safe drilling of nearly horizontal wells (75° Inclination) through Zubair depleted sandstone oil reservoir.
In this study, an integrated workflow was implemented mainly to build a geomechanical model using offset well data. The in-situ principal stresses and their orientations were obtained from wireline logging measurements and mini-frac tests. The repeat formation test (RFT) was used to constrain pore pressure. Rock mechanical properties were calculated using empirical correlations that have been derived from laboratory tests on core samples. Mogi–Coulomb failure criteria was used to address safe mud weight for drilling highly-deviated wells successfully. The model was verified with wellbore failure and also with wellbore instability events while drilling operations.
The results obtained from the geomechanical model shows that Zubair sections of planned wells would have narrow mud weight windows. The analyses also emphasized that the shale interbeds in the Zubair section require a mud weight of 1.5g/cc to limit wellbore breakouts. The presented study highlights that the geomechanical model can be applied as cost-effective tools to assess and address existing wellbore instability problems and to guide future well plans for better drilling efficiency with a reduced non-productive time (NPT) by using proper mud weight with respect to the inclination angle and the azimuthal direction.
The Zubair Formation is the most prolific reservoir in Iraq, which is comprised mainly of alternating shale and sandstone, with minor streaks of limestone and siltstone. It is recorded as an oil-bearing in 30 structures, which contain about 30% of Iraq's hydrocarbon reserves (Jassim and Goff, 2006). This multilayered reservoir has been subdivided based on its sand/shale ratio into five members: upper shale, upper sand, middle shale, lower sand, and lower shale. Upper and lower sand members are considered as reservoirs targeted for development, where it is known as the third and fourth pays, respectively. Thus, drilling a very high angle well through this formation has always been a challenge due to the weak nature of the shale sequence. Historically, over 90% of wellbore problems in the Zubair Formation are due to wellbore instability. Problems encountered while drilling through these shales and their consequences have included wellbore collapse, tight hole, excessive trip and reaming time, mud losses, stuck pipe, and sidetracks results in increasing the nonproductive time (NPT) and well costs (Gholami et al., 2014). These problems have often been managed using various operational limitations such as lower well deviations, limiting rates of penetration (ROP), avoiding sliding, etc. Unfortunately, this has placed constraints on reservoir development plans (Mehtar et al., 2010).