Bageri, B. S. (King Fahd University of Petroleum & Minerals) | Mahmoud, M. A. (King Fahd University of Petroleum & Minerals) | Al-Mutairi, S. H. (King Fahd University of Petroleum & Minerals) | Kuwait, Chevron (King Fahd University of Petroleum & Minerals) | Abdulraheem, A.
The filter cake evaluation involves many comprehensive testing and procedures to determine the filter cake properties such as thickness, mineralogy, porosity, permeability, and filtration to design the optimal mud program. For the maximum reservoir contact (MRC) and extended reach (ER) wells where the horizontal section could be 3000 ft or more in those wells, the filter cake formed by the drilling fluid varied from one section to another in the long horizontal section. Therefore, the process of filter cake removal in maximum reservoir contact and extended reach wells should consider the variation in the filter cake properties to achieve an efficient removal process.
This research focuses on evaluating the filter cake porosity and permeability profile through the horizontal wells. Moreover, the impact of the filter cake porosity and permeability on the removal process is presented in this work. To achieve the objective of this work, high pressure high temperature (HPHT) fluid loss test was conducted to form the filter cake using actual drilling fluid samples. The compositional and structural analysis of filter cake was carried out using scanning electron microscopy (SEM), X-ray diffraction (XRD), and X-Ray Fluorescence (XRF). The drilling fluid studied samples were collected from real field rig while drilling the horizontal section.
The results showed that the drilling operation was initiated with drilling fluid that was capable of forming a filter cake with low porosity (5 %) and permeability (0.01 md) to minimize the filtration volume. In the first part of the horizontal section the filter cake porosity and permeability increased sharply as more feet of horizontal section drilled. The porosity increased to about 35% and permeability to 0.25 md. After that it remains stable with slight decrease. This growth in the filter cake porosity from 5 to 35% reduced the liquid to solid ratio in the removal process from 28 gm per 500 ml up to 18 gm per ml.
The result of this work linked the filter cake properties (thickness, porosity, and mineralogy) in the maximum reservoir contact and extended reach wells with solid to liquid ratio needed to be used in the filter cake removal process. This work will help to reevaluate the filter cake removal and stimulation recipes that were designed based on constant filter cake properties.
There is an ever increasing need to extend the life of aging offshore structures beyond their original design life. Whether these structures are fixed offshore rigs or floating facilities, operators are continually looking for requalification and extension of the service life aimed at ensuring the integrity of the structure. With a continued requirement to produce oil or gas, either from the original fields or as a base for neighbouring subsea completions, many of these respective offshore installations are likely to remain operational for a period of time in the foreseeable future. The ageing offshore infrastructure presents a constant and growing challenge. Ageing is characterised by deterioration, change in operational conditions or accidental damages which, in the severe operational environment offshore, can be significant with serious consequences for installation integrity if not managed adequately and efficiently. In order to ensure technical and operational integrity of these ageing facilities, the fitness for service of these structures should be maintained.
Maximising the availability and productivity of the field, whilst operating safely and with minimal impact on the environment, is a major concern for requalification and life extension. Structural integrity management (SIM) and inspection campaigns are important inputs in the Asset Integrity Management and the maintenance of structural integrity is a significant consideration in the safety management and life extension of offshore installations. Detailed integrity assessments are needed to demonstrate that there is sufficient technical, operational and organisational integrity to continue safe operation throughout an extended service life. Information on history, characteristic data, condition data and inspection results are required to assess the current state and to predict the future state of the facility and the possible extension of service life. However unique environmental conditions, type of structures, fabrications and installation methodologies used in Middle East required attention in particular, development of hazard curves and risk mitigation of the potential regional degradation mechanisms. During the life-cycle of an offshore structure the ultimate capacity is also an important attribute that affects the life expectancy, requalification and life extension of the facility, and can significantly influence the reliability levels and operational costs.
This paper presents state of art practices in life extension of existing offshore structures and an overview of a regional hazard curves evaluation methodology and proposed regional correction factors represented risk to the integrity of a facility and the required procedures and re assessment criteria for deciding on life extension in particular the one with the importance for Middle East region. This paper also provides an overall view in the structural requirements, justifications and calibrations of the original design for the life extension to maintain the safety level by means of a maintenance and inspection programs balancing the ageing mechanisms and improving the reliability of assessment results
Narcizo, O. Melo (PEMEX) | Aguilar, A. Martinez (PEMEX) | Mendo, A. Rosas (PEMEX) | Gordillo, J. C. (PEMEX) | Ramondenc, P. (Schlumberger) | Burgos, R. (Schlumberger) | Basurto, J. R. Cervantes (Schlumberger) | Rodriguez, F. L. (Schlumberger)
An innovative approach to underbalanced perforating in horizontal and highly deviated wells uses a new perforating head specifically developed to leverage the conveyance and real-time telemetry capabilities of coiled tubing (CT) equipped with fiber optics. The results and advantages of this approach have been demonstrated in wells in mature Mexican fields featuring significant reach and pressure limitations.
In recent years, CT equipped with real-time fiber-optic telemetry has been a method of choice to perform interventions in deviated or horizontal wells, as it provides a cost-efficient and flexible alternative to heavier wired CT. In the Mexican fields, this real-time telemetry capability is used to accurately place the guns thanks to downhole casing collar locater and gamma ray tools. The need for pumping fluids to enable detonation, often performed during typical CT perforating operations, is eliminated through the use of a downhole microprocessor-controlled firing head, which is directed by commands sent from surface through the optical fiber.
The result is a nearly instantaneous detonation downhole and positive confirmation provided in real time through an array of sensors in the bottomhole assembly (e.g., accelerometers, pressure, and temperature). The absence of working fluid eliminates any concern of hydraulically loading the well or the need for shut-in, thus significantly reducing the extent of deferred production. It also mitigates uncertainties linked to the influence of downhole conditions on the behavior of working fluids or the potential malfunctions of drop balls. This system is capable of multizone, selective detonation, therefore improving operational flexibility through reduced gun runs. It is also compatible with any other traditional CT service and can easily be combined with a bridge plug setting, a nitrogen lift, or a cleanout within the same run. The approach and its associated workflow enabled a significant reduction in intervention turnaround time by cutting as much as 75% of the time necessary to detonate the guns once the depth has been correlated, while providing fast and clear confirmation of downhole detonation.
This evolved approach not only addresses the conveyance limitations of highly deviated and horizontal wells, it also greatly improves the safety, reliability, and efficiency of underbalanced perforating interventions by leveraging the real-time downhole monitoring and control capabilities of CT with fiber optic telemetry.
Feng, Cheng (Key Laboratory of Earth Prospecting and Information Technology, China University of Petroleum) | Mao, Zhiqiang (Key Laboratory of Earth Prospecting and Information Technology, China University of Petroleum) | Fu, Jinhua (PetroChina Changqing Oilfield Company) | Shi, Yujiang (PetroChina Changqing Oilfield Company) | Cheng, Yumei (Exploration Department, PetroChina Changqing Oilfield Company) | Li, Gaoren (PetroChina Changqing Oilfield Company)
For big variation of formation water salinity in Chang 8 stratum, Triassic, northwestern Ordos Basin, China, low resistivity contrast exists between oil layers and water layers. In order to increase the accuracy of log interpretation, accurate formation water salinity is a vital part. Based on the petrophysical theory, this paper summarizes and improves two methods to estimate formation water salinity. Firstly, reservoir resistivity-porosity cross plot method is introduced for oil-water layers and water layers. To be specific, resistivity and porosity log values of target reservoir are added to the cross plot. Data points, which are closest to the origin of coordinates, are selected as water layer ones. Then, formation water salinity is calculated by Archie formula. Secondly, shale water salinity is approximately regarded as formation water salinity. Because shale water salinity estimation is a nonlinear problem with small sample sets and there is no theoretical equation, Least Squares Support Vector Machine (LSSVM) is used for shale water salinity prediction. 9 parameters are extracted from lithology, resistivity and porosity log curves, among which, 5 are optimized as sensitive parameters by Principal Component Analysis (PCA). The effectiveness and reliability of resistivity-porosity cross plot and improved SVM method are tested by 23 formation water chemical analysis data. The average relative error of the former method is 19.79%, while that of the latter 27.57%. In addition, formation water salinity of another 50 wells are calculated by the two methods. Based on them, a salinity plane distribution map is drawn by Geomap software. In high salinity area, producing wells gather. Thus, one possible origin of formation water salinity variation is proposed. High salinity water moves into reservoirs with oil from source rock, which leads to high water salinity. In ultra-low permeability clastic reservoir with near source accumulation, formation water salinity probably varies significantly because of oil migration and accumulation. Furthermore, layers with oil often have higher formation water salinity, which is the main cause of low resistivity oil layers. Thus, the accurate formation water salinity calculated by the improved methods, will play an important role in the evaluation of low resistivity contrast oil layers and water layers.
Carbon Capture and Storage (CCS) is particularly attractive for the oil and gas industry due to the potential of Enhanced Oil Recovery (EOR). The presence of adequate well injectivity is identified as a prerequisite for CCS and CO2 EOR projects. Mineral precipitation in the vicinity of the well is suggested as a possible injectivity impairment mechanism. After mineral precipitation and formation dryout, continuous injection of CO2 into the formation could redistribute precipitates and alter injectivity. In this work, we investigated the effect of viscous force on precipitated minerals and the resulting consequences on permability and injectivity. The influence of supercritical CO2 injection rate, initial core permeability and saturating brine salinity were investigated. We observed that, injectivity impairment has a maximum immediately after mineral precipitation. Continuous injection of supercritical CO2 into the core after mineral precipitation is seen to reduce injectivity impairment induced by precipitated minerals. In most numerical and geochemical models, static injectivity impairment as a result of mineral precipitation is often assumed. Our findings suggest that injectivity remains dynamic throughout the injection process. Therefore, changes in CO2 injectivity after mineral precipitation could be complex to model and understanding of the processes is a good point to start.
AlMutwali, O. (Abu Dhabi Marine Operating Co.) | Khemissa, H. (Abu Dhabi Marine Operating Co.) | Alfelasi, A. (Abu Dhabi Marine Operating Co.) | Dama, S. (Abu Dhabi Marine Operating Co.) | AlNeaimi, A. K. (Abu Dhabi Marine Operating Co.) | Ahmed, S. N. (Abu Dhabi Marine Operating Co.) | Shrivastva, C. (Schlumberger) | Abdulrahim, J. (Schlumberger) | Girinathan, S. (Schlumberger)
Application of the legacy oilbased mud (OBM) borehole images in carbonates has posed challenges due to the limitation of resolution and borehole coverage; often providing too little for textural and sedimentological interpretation, and leaving a lot to be desired for optimal subsurface characterization. A new technology was required in UAE to acquire photorealistic images to decipher the carbonate heterogeneity for optimal characterization.
The Cretaceous carbonates of Abu Dhabi are very complex with varying heterogeneity through different reservoir intervals. To address various drilling challenges and coring requirements, OBM is being used by various operators in different acreages. Formation imaging becomes critical in such wells, where reservoir rocktyping and different enhanced oil recovery feasibility studies are planned. The study well shows the results of a new technology images in comparison with legacy OBM images and core. And, the image data is inverted for advanced processing to prepare standoff images and quantitative resistivity images for high resolution heterogeneity indicator.
The study well penetrates through a shallow marine carbonate setting ranging from shoal grainstone to the shelf setting wackestone and packstone exhibiting a lot of heterogeneity in facies distribution. In fact, a lot of variability was observed in the image logs against the interval of constant porosity observed in petrophysical logs. Stylolites and conductive seams seem to introduce a lot of barriers and baffles; however, stylofractures seem to be breaching the barrier in many intervals as well. The image log data was inverted to prepare the standoff images and quantitative resistivity images to understand the response of open vs. closed fractures; and vuggy/ mouldic porosity. The results were compared with the core photographs for validation of the interpretation. The high resolution heterogeneity indicators derived from the inverted images provided a means of highresolution facies typing; thereby providing electrofacies to be tied to petrophysical response for further reservoir rocktyping. The textural interpretation also helps in understanding the flow behavior. A detailed faciestyping with advanced interpretation is prepared to understand not only the geological characteristics, but also the variations in reservoir properties within seemingly similar facies.
This work presents the first account of interpretation based on a new technology for OBM formation imaging, with innovative inversion techniques. This also serves as a roadmap for carbonate reservoir characterization in Middle East in the wells drilled with OBM. Also, the encouraging results provide a trendsetting example of applications of this new technology.
Dac, The Nguyen (Schlumberger) | Sanders, Michael (Schlumberger) | Ngo Anh, Tuan Nguyen (Schlumberger) | Millot, Pascal (Schlumberger) | Rehman, Sadu-ur (Schlumberger) | Suzuki, Katsuko (Schlumberger) | Lawson, Michael (Talisman Energy Vietnam) | Jeow, Foo Say (Talisman Energy Vietnam) | Tran Van, Khanh (Talisman Energy Vietnam)
The Vertical Seismic Profile (VSP) technique is routinely used to create seismic images near the wellbore; traditionally, only the up-going wavefield is used to image the subsurface below the receivers. The standard VSP technique does not provide seismic image information above the well trajectory. The objective of this study was to produce a seismic image above the top receiver depth up to the seafloor by using the downgoing multiples recorded in the VSP data for a more complete seismic-to-well tie.
In VSP acquisition, the seismic source is positioned below Mean Sea Level and deployed above a downhole receiver. The source signal is recorded by a downhole receiver that is moved to cover a large number of depth levels in the well. The upgoing and downgoing arrivals are separated during processing; the up-going wavefield is used for subsurface illumination, whereas the downgoing wavefield and multiples are normally excluded from the processing. The standard VSP technique using the VSP upgoing wavefield gives a seismic image along the range of receiver depths and below the well trajectory. However, a VSP image can also be obtained from the downgoing multiple sequences in deep water.
The processing of sea surface multiple is used mainly to obtain a VSP image of formations above the top receiver depth; such an image is unattainable with the standard VSP technique. Our results show that illumination coverage increases significantly when using multiples versus primaries. In addition, reflectors above the shallowest receiver can be imaged by multiples, including the seabed itself. This can be useful for shallow hazard identification for sidetracks or to avoid the expense of infill nodal seismic below the rig (
By using the deepwater surface-related VSP multiples and the mirror-imaging technique, the VSP image was extended successfully above the well trajectory upward to the seafloor and shows a good correlation with the surface seismic section (
Beckert, Julia (Imperial College London) | Vandeginste, Veerle (Imperial College London) | John, Cédric M. (Imperial College London) | Guérillot, Dominique (Qatar Petroleum) | Foeken, Jurgen (Qatar Petroleum)
Recent ground-based studies of quarry cliff faces suggest hyperspectral imaging to be a convenient tool to distinguish highly similar carbonate phases in vertical cliff faces within short distances (
This paper presents the use of good quality field appraisal data to assess the shallow geohazards in locations planned for development well pads placement. For any hydrocarbon development, understanding the integrity of the surface and near-surface is important in the decision process of well pad placement and pipeline routing. The objective of this study was to assess risk of surface faults and the presence of shallow gas below the proposed surface facilities locations using available good quality 3D seismic, a high resolution digital elevation model and gas log data to analyse the shallowest 150m of the overburden in the development project area. The project area lies in the northern extent of the Albertine Rift basin, a tectonically active intracontinental rift system, with seismic activity in the region of 800 events per month.
By detailed interpretation and analysis of the 3D seismic, the study provided an insight into the structural architecture of the near surface and occurrence of shallow gas. The seismic data was of such high quality that attributes such as Variance and Dip Azimuth were used to interpret both basement and sediment propagating normal faults that extended to surface. The majority of the faults were found to align with changes in the surface topography or drainage pattern seen on the high resolution digital elevation model. Using a fault proximity zone of 200m the pad locations were categorised with regard to probability of surface fault hazard, as low, medium or high risk. Out of the 27 well pads that were screened, 5 pads locations were found to be in the high risk category, with proposed pad locations falling within the defined 200m fault proximity. This formed an important decision criterion on choice of the surface facilities location.
The work has demonstrated and identified high risk areas due to shallow faulting, with resulting pad moves whilst ensuring that environmental and social impact is minimised. In the studied area, no anomalously bright amplitudes were seen on the seismic in the shallow section. Also from the gas logs, no shallow gas was encountered in all 25 the exploration and appraisal wells in the area. The findings will also be taken into account in the pipeline routing process in order to minimise the traverse of major faults.
Development of the hydrocarbon resource in the project area will involve drilling of about 200 wells and hundreds of kilometres of excavation for inter-field pipelines. Use of the 3D seismic has demonstrated to be effective in this setting with early detection of high risk areas due to near surface faults. This desktop study resulted in a significant reduction of the scope of additional surveys and therefore a significant reduction in the cost of pre-development.
Haoran, Zhang (Oil and Gas Pipeline Transportation Safety of National Engineering Laboratory, China University of Petroleum) | Yongtu, Liang (Oil and Gas Pipeline Transportation Safety of National Engineering Laboratory, China University of Petroleum) | Mengyu, Wu (Oil and Gas Pipeline Transportation Safety of National Engineering Laboratory, China University of Petroleum) | Chen, Qian (Oil and Gas Pipeline Transportation Safety of National Engineering Laboratory, China University of Petroleum) | Ke, Li (Oil and Gas Pipeline Transportation Safety of National Engineering Laboratory, China University of Petroleum) | YueLong, Yan (Oil and Gas Pipeline Transportation Safety of National Engineering Laboratory, China University of Petroleum)
Coalbed methane has attracting much attention as a kind of the new energy source, with ever increasing demand in energy consumption. Pipeline networks of CBM fields are characterized by their complex topological structures and high investment costs. Therefore, the optimization of the pipeline network topology structure will be very helpful in lowering the production costs. The paper discusses four main structures: (1) the well gathering connection, (2) the nearby insertion connection,(3) the valve gathering connection and (4) the combination of well gathering and valve gathering connection. The optimal models which aim at minimizing total investment are solved by genetic algorithm with hybrid encoding by Hash table. The models have taken factors such as flow rate balance at nodes, constraints of the flow velocity, the minimum inlet pressure, maximum operating pressure, maximum number of wells connecting the valve block and the geographic condition into consideration. The paper comes up with a sort of regionally surviving convergence criterion which focuses on models that are strongly discontinuous and prone to be trapped in a local optimum. Taking 46 wells in a CBM field as an example, the paper works out the optimal topological connection for each structure. The result shows that the investment costs, calculated by the regionally surviving convergence criteria, are reduced by a maximum of 11.94% as compared to the traditional one. Also computing time is sharply saved. This study provides a guide line for reducing the cost of producing pipeline networks in CBM fields.