Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alkhamis, Mohammed M. (Missouri University of Science and Technology) | Mutar, Rusul A. (Ministry of Communications and Technology)
Lost circulation is a complicated problem to be predicted with conventional statistical tools. As the drilling environment is getting more complicated nowadays, more advanced techniques such as artificial neural networks (ANNs) are required to help to estimate mud losses prior to drilling. The aim of this work is to estimate mud losses for induced fractures formations prior to drilling to assist the drilling personnel in preparing remedies for this problem prior to entering the losses zone. Once the severity of losses is known, the key drilling parameters can be adjusted to avoid or at least mitigate losses as a proactive approach.
Lost circulation data were extracted from over 1500 wells drilled worldwide. The data were divided into three sets; training, validation, and testing datasets. 60% of the data are used for training, 20% for validation, and 20% for testing. Any ANN consists of the following layers, the input layer, hidden layer(s), and the output layer. A determination of the optimum number of hidden layers and the number of neurons in each hidden layer is required to have the best estimation, this is done using the mean square of error (MSE). A supervised ANNs was created for induced fractures formations. A decision was made to have one hidden layer in the network with ten neurons in the hidden layer. Since there are many training algorithms to choose from, it was necessary to choose the best algorithm for this specific data set. Ten different training algorithms were tested, the Levenberg-Marquardt (LM) algorithm was chosen since it gave the lowest MSE and it had the highest R-squared. The final results showed that the supervised ANN has the ability to predict lost circulation with an overall R-squared of 0.925 for induced fractures formations. This is a very good estimation that will help the drilling personnel prepare remedies before entering the losses zone as well as adjusting the key drilling parameters to avoid or at least mitigate losses as a proactive approach. This ANN can be used globally for any induced fractures formations that are suffering from the lost circulation problem to estimate mud losses.
As the demand for energy increases, the drilling process is becoming more challenging. Thus, more advanced tools such as ANNs are required to better tackle these problems. The ANN built in this paper can be adapted to commercial software that predicts lost circulation for any induced fractures formations globally.
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) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids)
Equivalent circulation density (ECD) management is a key factor for the successfulness of the drilling operations, especially when dealing with narrow mud-weight windows. Poor management of ECD can result in unsafe and/or inefficient drilling as well as an increase in drilling cost due to associated nonproductive time (NPT). Different parameters can affect the ECD directly or indirectly including, but not limited to, wellbore geometry, cuttings, hole cleaning efficiency, flow rate, and rheological properties of the drilling fluid. However, the magnitude of the effect of each parameter is not well understood. In this paper, a comprehensive statistical analysis using the correlation coefficient was conducted using real field data to investigate the effect of three controllable factors - solid contents (SC), yield point (Yp), and plastic viscosity (PV) - on ECD.
Monitoring and reevaluation of petrophysical attributes in a mature field under production for many decades is crucial for optimizing production and further development planning. In this case study, a multidisciplinary approach is deployed for formation evaluation and reservoir characterization using logging-while-drilling (LWD) sensors spanning formation volumetrics, fluid analysis, high-resolution image interpretation, and geomechanics to confirm remaining oil saturations and help identify recompletion intervals. LWD technologies were used in four wells in Sahmah field of Oman to provide an integrated petrophysical and geomechanical field study using a bottomhole assembly (BHA) including gamma ray, resistivity, formation bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure testing sensors. A deterministic multimineral petrophysical model was used to derive formation volumetrics and fluid analysis. Geomechanical interpretation used high-resolution microresistivity imaging, acoustic slownesses, and formation pressure data to verify principal stress orientations and to quantify pore pressure and horizontal minimum and maximum stress magnitudes. These data were then correlated with historical data to evaluate sweep efficiency and residual fluid saturations. LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data compared to previous traditional wireline data acquisition.
Chemical EOR is an increasingly employed approach used to enhance oil recovery by combining changes in fluids mobility, macroscopic sweep, interfacial tension, etc. to essentially improve, or extend the economic life of a water flood. It includes flooding with polymer, surfactant, alkaline/surfactant, alkaline-surfactant-polymer (ASP), CO2 and / or other miscible gases which is often combined with waterflood (
The paper evaluates the main chemical changes that occur in the system for each EOR approach –– and shows how these changes, including in situ reservoir reactions and the stability/instability of the EOR packages themselves can exacerbate a range of PC-related challenges especially when considering the likely production of up to three different fluids: formation water, the EOR flood medium and any previous flood water from previous secondary recovery
The paper includes modelling results, laboratory results to validate model predictions as well as examples from field case studies to illustrate the impact of the chemical changes referred to above. Specific highlights include the impact of the use of either high- or low-pH EOR fluids on scale control, corrosion control and asphaltenes control; for scale it examines both inhibitor performance
The overall conclusion is that chemical EOR can have significant impact on PC and that these should not just be considered at the design stage and not just for the injection system but also to take into account the impact these may have on production wells following breakthrough of flood waters, showing that essentially each new or exacerbated PC issues can be predicted or at least anticipated with the required degree of confidence before implementation of EOR.
Capillary pressure is a crucial step in reservoir properties definition and distribution during static and dynamic modelling. It is a key input into saturation height modelling (SHM) process, understanding the fluid distribution and into reservoir rock typing process. Capillary pressure models provide an insight into field dynamic for the identification of swept zones and provide another calibration besides the log calculated saturation. Capillary pressure curve tends to be more complex in carbonates in comparison to sandstone reservoirs because of post deposition processes that impact the rock flow properties, hence complex pore throat size distribution (uni-modal, bi-modal or tri-modal). Therefore, accurate determination of this property is the cornerstone in the reservoir characterization process.
Capillary pressure can be obtained using several experimental techniques, such as mercury injection (MICP), centrifuge (CF) and porous plate (PP). Each method has its own inherited advantages and disadvantages. The MICP method tends to be faster, cheaper and provides a full spectrum of pore throat size of a plug. Whereas, the PP method can be carried out at reservoir conditions with minimum required corrections.
In this paper, a detailed workflow for quality control capillary pressure is discussed. The workflow is sub-divided into three main parts: Instrumental and experimental level, core measurement level and logs level. Experimental level starts with proper designing the actual procedure of the capillary pressure experiment. Parameters such as pore volume, bulk volume and grain density are investigated at core measurement level. In geological-petrography montage, all petrography data; X-Ray Diffraction (XRD), Scanning Electron Microscope (SEM), thin section and computed tomography scan (CT) are used along with the capillary pressure curve for assessment. Comparing various methodologies of experimental technique carried out on twin plugs, if exist, are also investigated. The capillary pressure that passes the previous QC steps is used as input into saturation-point comparison as a logs level QC. The saturation calculated from capillary pressure is compared to log-derived water saturation eliminating any issues with porosity and permeability of the trims and provides insight to the uncertainty level in the model. As an additional step, the MICP measurements are fitted with bi-modal Gaussian basis functions with two practical benefits. First, the quality of this fitting is a useful indicator for the evaluation of pore structure complexity and the identification erroneous measurements. Second, the fitting parameters are useful inputs for geological interpretation, rock typing and SHM. This rapid and automated workflow is a useful tool for screening, processing and integration of large-scale capillary pressure data sets, a key step in integrated reservoir description, characterization and modelling.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Alsaba, Mortadha T. (Australian College of Kuwait) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids) | Al-Bazzaz, Waleed H. (Kuwait Institute for Scientific Research)
Lost circulation is a unique challenge unlike other factors contributing to non-productive time (NPT). Due to the variability in the nature and type of lost circulation prone formations; there is no universal solution to this challenge. This publication presents a new approach to guide the decision-making process of which and when to apply a certain treatment as compared to another. If implemented correctly, a significant reduction in NPT related to lost circulation can be expected. Also, the cost of each treatment, as well as the NPT that is associated with the treatment, were examined in this study. Lost circulation events for three formations which are the Dammam, Hartha, and Shuaiba were gathered from over 1000 wells drilled in Basra oil fields, Iraq using various sources and reports; the treatments were classified by scenario –partial, severe, and complete losses – as well as cost, efficiency, and formation types. This paper is developed based on probabilities, expected monetary value (EMV), and decision tree analysis (DTA) to recommend the best-lost circulation strategy for each type of losses.
This paper utilizes probability and economics in the decision-making process. This is the first study that considers a detailed probability and cost to treat the lost circulation problem. Thousands of treatment scenarios for each type of losses are conducted, and the EMVs for all scenarios are calculated. For each type of losses, the lowest EMV treatment strategy- that is practically applicable in the field and makes sense- is selected to be used to treat each type of losses to minimize NPT and cost. If the losses didn't stop after utilizing the proposed treatment strategies, it is recommended to use liner hanger to isolate the losses zone and then continue drilling. A change in well design is also suggested to help to minimize NPT and cost. In addition, a formalized methodology for responding to losses in the Dammam, Hartha, and Shuaiba formations is established and provided as means of assisting drilling personnel to work through the lost circulation problem in a systematic way.
One challenge in drilling wells in Basra oil fields is the inconsistency of approaches to the lost circulation problem. Therefore, the result of this data analysis provides a path forward for the Basra area lost circulation events and suggests probable methods that can be used in similar formations globally. Additionally, the methodology can be adapted to studying other types of formations and drilling challenges have the same geological properties in any major oil field.
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) | Alsaba, Mortadha T. (Australian College of Kuwait) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids) | Al-Bazzaz, Waleed H. (Kuwait Institute for Scientific Research)
The rate of penetration (ROP) plays a major role in reducing drilling costs, making it an important area of investigation. There are various controllable and uncontrollable factors that affect the ROP, and the variation in these variables affecting the ROP made it a very pivotal drilling parameter that has a significant effect on non-productive time. In this work, sensitivity and statistical analysis were carried out using data from over 1000 wells in Basra oil fields, Iraq. The scope of this work is to determine the effect of rheological properties on ROP, to provide a method for estimating the recommended range for drilling fluid properties based on data mining techniques.
In this work, huge real field data from over 1000 wells drilled in Basra oil fields, Iraq were gathered and analyzed to better understand the characteristics of a drilling fluid that enhance ROP and quantify the impact of each drilling fluid rheological properties on ROP. The data used in this study were collected from mud logging data, daily drilling reports (DDR), and geological information. Statistical and sensitivity analyses were performed in order to identify the relationship between ROP and drilling fluid rheological properties. The correlation coefficient (CC) was utilized to understand the effect of solid content (SC), yield point (Yp), and plastic viscosity (PV) on ROP. The results showed that SC is the most influential rheological property on ROP, then PV and finally Yp. In addition, this work demonstrates how bit hydraulics can be improved by means of modifying the rheological properties rather than adjusting the flow rate or nozzle size.
Large-scale collection and interpretation of field data or in other words "data mining" can be considered as a strong tool in understanding the impact of different parameters on the ROP in order to estimate the recommended range of rheological properties, which will result in improving the ROP.
The study objective is to determine the major factors controlling on acoustic and geomechanical properties of carbonate rocks of Jurassic D5 Member of Dhruma Formation. The study integrates petrophysical, petrographic, and geomechanical analysis to characterize different lithofacies, diagenetic properties, shear and compressional wave velocity, rock strength, dynamic elastic moduli, porosity and permeability of carbonate rocks. A total of sixty samples were collected, petrographic thin sections and Scanning Electron Microscopic images were prepared, small cubes and core plugs were prepared for porosity and permeability measurements as well as wave velocities and point load index tests. Porosity and permeability exhibited moderate to poor correlations. P-wave and S-wave velocities are moderately correlated with porosity. However, they showed better correlation with permeability. Poor to moderate direct correlation between dynamic elastic moduli (Poisson ratio and Young modulus) and porosity were found. The lithofacies with large fracture intensity are related to small P-wave velocity values. Four classes were found based on pore type and diagenetic classifications control on acoustic properties: Class 1 is characterized by moldic and intraparticle pore types with limited microporosity, Class 2 is characterized by intensive micro-fracturing, class 3 is intensively cemented, and Class 4 is characterized by microporosity. Micro-fractures pore type samples show the best wave velocity versus porosity correlation followed by densely cemented microporosity and finally moldic and intraparticle show the weakest correlation. Vertical semi-variograms were measured for P and S-wave velocity as well as porosity. A spherical model was found for P and S-wave velocities with zero nugget values and sill values equal to 3 meters. Hole effect reflecting the control of cyclicity was found. Porosity semi-variogram shows exponential modeling with zero nugget value and sill value equal to three meters. This difference in semivariogram between velocity and porosity supports weak and moderate correlations between them.
Alcantara, Ricardo (PEMEX E&P) | Santiago, Luis Humberto (PEMEX E&P) | Fuentes, Gorgonio (IMP) | Garcia, Hugo (IMP) | Romero, Pablo (IMP) | López, Pedro (IMP) | Angulo, Blanca (IMP) | Martinez, Maria Isabel (IMP)
The Naturally Fractured Reservoirs (NFR) constitute a challenge for the oil industry due to its importance in hydrocarbon production and the technical complexity they represent, because well's productivity in carbonated formations is influenced by fracture systems that govern the fluids motion within reservoirs. This approach is oriented to the analysis of a very complex NFR, where we show the results obtained through a dynamic characterization methodology focused on new opportunities in a High Pressure-High Temperature (HP-HT) coastal mature oilfield with high water cut production. The proposed methodology is based on a full analysis starting from the pressure-production historical data, fluids properties, dualporosity material balance, a detailed static model update (petrophysics, core analysis, petrography, fracture analysis, sedimentology-diagenesis and structural geology), flow units discretization, Water-Oil Contact (WOC) advance monitoring in each block, Pressure Transient Analysis (PTA) (determination of preferential flow direction and interference), and Rate Transient Analysis (RTA). This methodology allowed to determine the real Original Oil in Place (OOIP) and the proper recovery factor according to the type of NFR and its characteristics, to detect different WOC's for each block that were hydraulically connected to each other but with a different dynamic behavior among them, the detection of heterogeneities, facies changes and faults that originally were not mapped, sweet spots location, better distribution of the petrophysical properties, fracture analysis, static model reinterpretation based on the dynamic behavior, reservoir connectivity analysis (among blocks) and the generation of improved production forecasts based on an exploitation strategy especially designed for the current conditions and needs of the field; all of this contributed to have a better understanding of the reservoir and a good numerical simulation model.
Li, Feng (Southwest Petroleum University) | Xie, Xiong (CNOOC-Shenzhen) | Huang, Li (CNOOC-Shenzhen) | Zhou, Luyao (CNOOC-Shenzhen) | Chang, Botao (Schlumberger) | Wang, Chao (Schlumberger) | Wang, Fei (Schlumberger) | He, Chengwen (Schlumberger)
In China, the main sandstone reservoir M of the LF oilfield entered the mature development stage with high water cut (average 93%) and 66.1% recovery. Remaining oil exists vertically in the H layer at the top section of this massive bottomwater reservoir and laterally at margins of current development area with less well control. The H layer consists of several thin (0.5 to 2 m) sand sublayers interbedded with calcareous tight sublayers with low permeability; the effective oil drainage radius of single borehole is 100 to 150 m. Maximum reservoir contact (MRC) technology was employed to increase drainage area and volumetric sweep efficiency for optimal production and recovery to rejuvenate this mature reservoir.
In an original hole with 98 to 99.9% water cut targeted for a workover operation, two new laterals were sidetracked to comprise a three-lateral MRC configuration with openhole completion to develop the SL1 target sublayer of the H layer. The success of MRC wells depends on an efficient openhole sidetrack and azimuth turning. Moreover, multilaterals need to precisely chase the sweet zone in the reservoir. Drilling into overlying shale causes borehole collapse, and penetrating the underlying tight zone causes fast bottom water breakthrough. Low resistivity contrast increases the difficulty of distinguishing the target zone from the shoulders. Sparse well control and limited seismic resolution bring high structural and stratigraphic uncertainties. Accordingly, effective services were equipped to overcome these challenges to achieve the required engineering and reservoir objectives. The new-generation hybrid rotary steerable system (RSS) tool provides stable, rapid, and accurate steering control, even with high dogleg severity, to achieve engineering objectives. With a balance between resolution and depth of investigation (DOI), high-definition deep-looking resistivity inversion uses the Metropolis coupled Markov chain Monte Carlo method to clearly identify multiple layers (more than three) within an approximately 6 m DOI, formation resistivity distribution, anisotropy, and dip, even in this low-resistivity-contrast environment. Reservoir details could be clearly unveiled to help MRC lateral steering along the thin target. Furthermore, a wide-range-displacement electrical submersible pump (ESP) helps optimize openhole performance.
Six new laterals were drilled in three MRC wells. Hybrid RSS tools provided 100% openhole sidetrack success rate, and laterals were turned laterally with 15 to 70° azimuth change and 200- to 570-m displacement to maximize the drainage area. Deep-looking inversion revealed high-definition reservoir details by delineating three key boundaries and four adjacent layers' profiles simultaneously and identifying target zone's thickness and property variation. The target sand is 0.5 to 2 m thick with resistivity of 2 to 9 ohm-m, surrounded by interbeds with resistivity 8 to 10 ohm-m. Within the refined 3D reservoir model, the horizontal laterals efficiently chased the top section of effective target sand while avoiding high-risk shoulders. Total 4298-m horizontal footage was achieved in six laterals with net-to-gross 91% in the SL1 thin, low-permeability reservoir. With the proper ESP configuration, approximately 688,500 bbl of oil have been produced as of December 2018. Especially in two workover MRC wells, after approximately 2.5 years of production, the current water cut is 96 to 97%, lower than water cut (98 to 99.9%) before the workover operation, and daily oil production increased significantly.
Integrated drilling, logging, and production services provided MRC efficiency to rejuvenate this thin, low-permeability and low-resistivity mature reservoir.