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.
Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Hilgedick, Steven A. (Missouri University of Science and Technology) | Alkhamis, Mohammed M. (Missouri University of Science and Technology) | Alshawi, Yousif Q. (Basra Oil Company) | Al-Maliki, Madhi A. (Basra Oil Company) | Alsaba, Mortadha T. (Australian College of Kuwait)
Wells drilled in the Rumaila field are highly susceptible to lost circulation problems when drilling through the Hartha formation. This paper presents a comprehensive statistical work and sensitivity analysis models of the lost circulation events for more than 300 wells. Moreover, this study will demonstrate an integrated analysis regarding the most significant drilling parameters, which have a pivotal impact on the lost circulation to provide the greatest chance of mitigating or avoiding lost circulation in the Hartha formation.
Lost circulation events are extracted from daily drilling reports, final reports, and technical reports. Key drilling parameters are analyzed using statistical software to understand the relationship between the mud losses and various drilling parameters such as MW, ECD, Yp, ROP, SPM, RPM, WOB, flow rate, and bit nozzles. The sensitivity analysis is conducted to examine the impact of each parameter in all models. In addition, variance inflation factor (VIF) method is used to test for the multicollinearity phenomena in each model to maximize the accuracy and to obtain a solid mathematical model.
The volume loss model is conducted to predict lost circulation in the Hartha formation. As a proactive action, this model can be used to estimate the volume loss prior drilling the Hartha formation. Observations that have been made from the volume loss model are MW, ECD, and Yp have a significant impact on lost circulation respectively; however, SPM, RPM, and ROP have a minor effect on the volume loss model. Equivalent circulation density (ECD) model is obtained to estimate ECD in the Hartha formation, and from this model can be deduced that MW, ROP, and Q have a significant impact on ECD respectively; nevertheless, RPM and Yp have a minor impact on the ECD. The rate of penetration model is made to estimate ROP in the Hatha formation. It is concluded that WOB, SPM, and RPM have a significant impact on the ROP respectively, but MW, ECD, and Yp have a minor influence on the ROP. In addition, engineering solutions are developed to give a clear image regarding lost circulation, and it will provide a unique statistical study and coherent sensitivity analysis of all factors which have an essential or a small impact on this issue.
Due to the lack of published studies for this formation, this study will provide a unique understanding for lost circulation events, drilling fluid properties, and operational drilling parameters, which have a prominent or a minor impact on the mud losses issue. Lost circulation will be illustrated in terms of causes, consequences, recommendations, and guidelines to reduce or avoid unwanted losses. In addition, this work can serve as a practical resource for drilling through the Hartha formation.
Al-Aulaqi, Talal (Petroleum Development Oman L.L.C.) | Dindoruk, Birol (Shell Technology Houston) | Zhang, Etuan (Shell Technology Houston) | Ward, David (Shell Technology Houston) | Al-Azri, Nasser (Petroleum Development Oman L.L.C.)
Thermal EOR has been applied in different reservoirs in Oman to maximize the production from heavy oil prospects. PDO consider the highest HSE standard in their field operation to protect people and the integrity of the assets. In thermal EOR one of the highest HSE and risk integrity is the drastic increase of acid gas production mainly (H2S and CO2).
Historically, the quantification of the acid gas development in thermal EOR developments has been challenging, either leading to underestimation of the acid gas levels or overdesigning the material type with huge cost associated which impact the commerciality of the project especially at the current low oil price. Thus, improvement of the thermal souring prediction capabilities is required for the risk assessment and fit for purpose material selection rather than exotic option.
This work shows the results from an integrated subsurface and surface engineering collaboration to define the geochemical sources of souring in the thermal projects
Al-Ajmi, Abdullah (Kuwait Oil Company) | Al-Rushoud, Abdulaziz (Kuwait Oil Company) | Gohain, Ashis (Kuwait Oil Company) | Khatib, Faiz I (Kuwait Oil Company) | Al-Naqa, Faisal (Kuwait Oil Company) | Al-Mutawa, Faisal (Kuwait Oil Company) | Al-Gharib, Majed (Kuwait Oil Company) | Birthariya, Sudhir (Kuwait Oil Company) | Mago, Ankit (Kuwait Oil Company) | Al-Mekhlef, Alanoud (Kuwait Oil Company) | Al-Tarkeet, Bader (Kuwait Oil Company) | AlAli, Yaqoub (Kuwait Oil Company) | Rossi, Arnaldo (Newpark Drilling Fluids) | D'Angelo, Dario (Newpark Drilling Fluids) | Spagnoli, Nazareno (Newpark Drilling Fluids) | Samaan, Fady (Newpark Drilling Fluids) | Rane, Praful (Newpark Drilling Fluids) | Scolari, Alberto (Newpark Drilling Fluids)
Shale stability and differential sticking are the main challenges while drilling through shale and sand sequences. Conventional mud systems cannot always provide the required wellbore stability and sustained high overbalance, which has led to an increase in use of ‘customized fluids’.
Offset wells were reviewed to identify the issues while drilling this challenging trajectory through troublesome stressed Zubair shale and sand sequences. This review revealed serious well-bore instability, pack offs, differential stuck pipe leading to the loss of downhole tools and sidetrack operations.
Traditionally, oil-based mud (OBM) have been used while drilling these formations with high NPT hours. Due to necessity of comingling two sections in a single section, it was necessary to identify a fluid's solution, which can provide good borehole stability.
A customized drilling fluid system was designed by using deformable sealing polymer (DSP, deformable size) in conjunction with Synthetic Resilient Graphite and Sized Calcium Carbonate (CaCO3) in conventional OBM. These Nano particles effectively plug the pore throats and minimized the fluid invasion, which was confirmed by particle / permeability plugging tests under down hole conditions to overcome below challenges. Improve hole stability through stressed shale formations Minimize risk of differential stuck pipe across low pore pressure formations Mitigate induced losses by utilizing unique wellbore-strengthening technique Enhance hole-cleaning efficiency at critical angle
Improve hole stability through stressed shale formations
Minimize risk of differential stuck pipe across low pore pressure formations
Mitigate induced losses by utilizing unique wellbore-strengthening technique
Enhance hole-cleaning efficiency at critical angle
Drilling, logging, running and cementing liner was successfully completed in the commingle section without any incident. There was no NPT related to well-bore instability or differential sticking tendency reported. Very low torque and drag was observed in addition to enhanced well-bore cleaning in the high angle section.
This paper will present the success of the deformable sealing polymer in OBM utilized to comingle Upper Zubair shale and Ratawi shale with case histories for reference.
Guo, Boyun (University of Louisiana at Lafayette) | Li, J. (University of Petroleum China Beijing) | Cai, Xiao (University of Louisiana at Lafayette) | Zhang, Xiaohui (University of Louisiana at Lafayette) | Wang, Gui (Southwest Petroleum University)
Lost circulation is commonly recognized as one of major drilling complications that cause low efficiency and a high cost in oil or gas well drilling. The current practice of mitigating lost circulation with lost circulation materials (LCM) is still empirical due to the lack of understanding of near-wellbore conditions. This work the first time uses pressure transient data analysis method to infer the near-wellbore conditions in lost circulation wells. The fluid level survey data can be converted to bottomhole pressure
Schedule Session Details Expand All Collapse All Filter By Date All Dates Sunday, November 12 Monday, November 13 Tuesday, November 14 Wednesday, November 15 Thursday, November 16 Filter By Session Type All Sessions Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Training Course/Seminar Sunday, November 12 08:00 - 17:00 Production Optimisation System Instructor(s) Atef Abdelhady The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. Learn More 08:00 - 17:00 Practical Depth Conversion and Depth Imaging for the Interpreter Instructor(s) Pavel Vasilyev Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process. Participants will gain an understanding of depth conversion methodologies and QCs for validity of methods used. Learn More 08:00 - 17:00 Marginal Field Development and Optimisations Instructor(s) Abdolrahim Ataei Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. This session will show how chip technology has resulted in a miniaturised Electron Paramagnetic Resonance (EPR) spectrometer for online monitoring of asphaltenes (a chemical that clogs oil wells). The EPR sensor technology developed in the laboratory has been successfully deployed in major oil and gas fields across the world. This technology is used to monitor the concentration of asphaltenes in real-time and to minimise the use of environmentally hazardous chemical inhibitors in energy production. Employee suggestions for improvement cover a wide variety of topics such as economic efficiency, productivity, safety, operability, environmental friendliness, and to a greater or lesser extent, has led to efficient and improved operations.
Kundu, Ashish (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Voleti, Deepak Kumar (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Rebelle, Michel (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Al Housani, Habeeba Ali (Abu Dhabi Co For Onshore Petroleum Operations Ltd)
The studied lower Cretaceous carbonate ramp deposits are heterogeneous with pervasive diagenetic processes leading to complex pore network and rock texture. Before this study, field development was based on log based water saturation modeling. This saturation modeling was dependent on the hydraulic flow units and porosity classes, which was meant to be, but was not explicitly representative of the defined geologic facies. The assignment of the relative permeability data is also very challenging in the absence of proper Rock Type model. Often in carbonate reservoirs, there is no direct or linear relationship between Reservoir Rock Types (RRT), sedimentological facies assemblages and water saturation distribution across the field. Hence, accurate integration of the sedimentological, diagenetic, depositional environment information and petrophysical properties is essential in building a robust RRT model. This RRT model can then explain the rock-fluid interaction through a reliable saturation height model.
In the first part, the paper illustrates the workflow which involves integrating lithofacies, depositional packages, degree of cementation, pore-type from sedimentology and relating resultant pore-typing to core porosity–permeability data. This workflow resulted in a strong reservoir rock typing scheme, which was key in building a robust saturation height model. Precisely, this was achieved by assigning "most-of lithofacies and diagenetic indicators" to each rock type defined. In the second part, a Variable Saturation Height Function (VSHF) was developed using mercury injection capillary pressure (MICP) data. The function was made variable with depth by bringing one or both of the reservoir parameters (Phi and K) into the equation. Most importantly, VSHF explicitly scans the lower and upper Sw boundary of a particular rock type and helps in removing the skewness in the Sw difference histogram between model and log Sw. One of the important steps in the workflow was to normalize the MICP data to log derived Sw values, provided the confidence on the Sw calculation from logs is high. After stress and closure correction, the normalization of the reservoir Pc data was achieved through an independent correction factor.
Both of the workflows (rock typing and saturation height modeling) were built based on data from 30 cored wells. The workflows were tested on 15 cored wells and more than 600 non-cored wells. Rock type maps were found to be more correlatable with reservoir quality maps than lithofacies maps alone. This is a result of the diagenetic processes undergone by the rock during and after deposition modifying the original depositional controlled pore architecture. With this approach the water saturation distribution was more consistent with logs and core derived Sw data.
The workflows shown in this paper are reliable and can be extended to other carbonate fields’reservoir characterization.
The aim of this study is to propose a stratigraphic and sedimentary framework though the integration of available sedimentary, diagenetic and petrophysical data, which will be utilized in the construction of a high resolution stratigraphic framework, as an input into comprehensive review and update of an existing model of heterogeneous carbonate reservoir in a mature field in Abu Dhabi, UAE.
Depositional facies have been defined in cored wells, subsequently were associated taking into account the biologic and sedimentary processes in response of carbonate growing and sea level changes, allowing the identification of the main stratigraphic surfaces.
Surfaces can extend the correlation along the field and define the model of facies that, with the evidence provided by cores, can recreate and predict the different regressive-transgressive cycles in high resolution which the carbonate platform were undergone during its evolution.
Diagenetic evolution, interpreted through laboratory observations, was integrated with facies and petrophysical evaluation allowing the understanding of the spatial distribution of petrophysical properties within a heterogeneous reservoir and define a new set of facies which will be used in the generation of geological static model.
Application of sequence stratigraphy methods in cores, and extended in logs allowed the identification of six depositional sequences, with thicknesses of 2 to 4 meters each, corresponding to the phases of carbonate platform growth. Within each depositional sequences, typical cycles were defined that support the understanding in the association of facies and their relationship during the deposition.
The identification of sedimentological cycles not only genetically organizes the facies and predicts the stacking pattern, but also makes possible to find an excellent correspondence between cycles from lowstand system track intervals with good to excellent permeability values, and cycles from transgressive system track intervals with low permeabilities.
Many of the sequence stratigraphy published articles driven for the most important reservoirs along the Arabian Plate, provide an excellent tool in the regional correlation. However, they are not enough to be used in the reservoir characterization in detail that is required during the development of the field neither as input data in the generation of geological static models that use the sedimentary trends as constrain to populate the petrophysical properties.
Integrated seismic reservoir characterization of carbonate rocks potentially thwarts difficulties arising from reservoir heterogeneity owed to a complex geological history. The featured interdisciplinary workflow reconciles geological, geophysical and engineering components to address reservoir complexity in terms of stratigraphic architecture coupled with a distribution of layer properties that honors flow zonation. Primarily, this workflow calls for a combination of hydraulic flow unit definition embedded in sequence stratigraphy and is further augmented by seismic attribute analysis (i.e., seismic inversion, frequency decomposition of amplitude, etc.), rock physics, and geostatistical techniques to characterize an UAE onshore oil reservoir located within a Lower Cretaceous carbonate sequence (i.e., lower member of Shu'aiba Formation; Strohmenger et al., 2010). Our results to-date encourage us to further characterize the reservoir applying geostatistical techniques (seismic stochastic inversion, fuzzy math) in a future companion paper.