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Baumgardner, Lonny (SDX Energy) | Ahamiri, Jamal (SDX Energy) | Kuyken, Chris (AlMansoori Specialized Engineering) | Farouk, Mohamed (AlMansoori Specialized Engineering) | Jammeli, Kamel (AlMansoori Specialized Engineering) | Merchan, Ylmer (AlMansoori Specialized Engineering)
Abstract A 5-well rig-less & explosiveness abandonment campaign by 2 project partners operator and service provider was made a reality in Morocco whereby a novel method of cementing squeeze of perforations and an annular fill-up were established in one single operation. This is called LEAN abandonment and the method was masterminded as a result of intense collaboration between both partners. The method is scale-able and has full merit to target existing legacy wells for abandonment in Morocco and world-wide where appropriate. In this LEAN approach the tubing and annulus were communicating via SSD / non-explosive created tubing punch by holding backpressure on the annulus till perforations squeezed or pressure lock-up and subsequently immediately opening the annulus and releasing the annular pressure whilst continuing pumping and filling the annulus with some 800 m of cement creating the firm additional barrier. Clinical planning by operator and service provider on a establishing a new abandonment process that is opening-up further in-country and beyond opportunities was the critical success factors in this work. It led to organic improvement on a well by well basis in the campaign, it resulted in safe and successful operations and achieving abandonment objectives cementing to surface in tubing and annulus. LEAN Abandonment forms a paradigm shift. It may be different in different down-hole settings and there is no single solution however like in our case working a bottoms-up approach has resulted the lowest cost solution and having done so ways to improve overall safety and efficiency were identified. The use of non-explosive technology is a very good example.
Kholaif, Yasser (NOSPCO) | Elmaghraby, Mahmoud (NOSPCO) | Nago, Annick (Baker Hughes) | Embry, Jean-Michel (Baker Hughes) | Basu, Pramit (Baker Hughes) | Perumalla, Satya (Baker Hughes) | El-Said, Mohamed M. (Baker Hughes) | ElMenshawy, Ali (Baker Hughes) | Baghdadi, Ahmed (Baker Hughes)
Abstract Drilling challenges in offshore Nile Delta have been largely documented in the literature. Operators are often confronted with drilling problems related to shale swelling, cavings, tight holes in combination with increased risks of lost circulation in some of the highly depleted formations. The Kafr El Sheikh shale in particular, has been linked to many instances of wellbore instability, due to its mineralogical composition (estimated to be mostly smectite, >70%). From offset well drilling experience, it could also be noticed that insufficient mud weight was often used to drill through the Kafr El Sheikh Shale, causing wellbore failure in shear due to lack of support of the wellbore wall. In the past, multiple mud weight designs have been implemented relying solely on pore pressure as lower bound of the mud window. With the increased use of geomechanics, it has been demonstrated that the lower bound should be taken as the maximum of the pore pressure and borehole collapse pressure, thus accounting for the effects of formation pressure, horizontal and vertical stresses, rock properties as well as wellbore trajectory. It has been proven that slight overpressure is often encountered halfway through the Kafr El Sheikh formation, which would typically result in slightly higher borehole collapse pressures. In the study fields, the operator expressed interest in drilling highly deviated wells (> 60-70 degrees). This raised concerns for increased drilling challenges, especially in the Kafr El Sheikh. A comprehensive and systematic risk assessment, design of a fit-for-purpose solution and its implementation during drilling took place in the fields of interest. Offset well data analytics from the subject fields supported a holistic evaluation of drilling risks associated with the Kafr El Sheikh, providing good understanding of stress sensitivity on deviation, azimuth and lithology. Upon building a robust geomechanical model, calibrated against offset well drilling experience, pre-drill mud weight and drilling practices recommendations were provided to optimize the drilling program. Near real-time geomechanical monitoring was implemented which helped to manage the model uncertainties. The implementation of a holistic risk assessment, including geomechanical recommendations and near real-time geomechanical monitoring, was effective to lead the drilling campaign successfully. As a result, three high angle wells (> 60-70 degrees) were drilled through the challenging Kafr El Sheikh formation without any hole instability. An integrated risk assessment of hole instability, managed in stages (pre-drill and during drilling), has helped to understand and simulate the behaviors of the formation. Proactive decisions have established a controlled drilling environment for successful operations.
Wijaya, Aditya Arie (Halliburton) | Wu, Ivan Zhia Ming (Halliburton) | Parashar, Sarvagya (Halliburton) | Iffwad, Mohammad (Halliburton) | Yaakob, Amirul Afiq B (Petronas Carigali) | Tolioe, William Amelio (Petronas Carigali) | Sidid, Adib Akmal Che (Petronas Carigali) | Ahmad, Nadhirah Bt. (Petronas Carigali)
Abstract In recent years, the development of frontier areas brings added challenges to formation evaluation, especially thinly bedded reservoirs. It is challenging to evaluate such reservoirs due to the low resistivity values and high shale volume, which masks the contrast between water and hydrocarbon zones. Using conventional approaches in these types of reservoirs will underestimate the hydrocarbon potential and reserves estimates. A study has been carried out of the thin-bed laminated reservoir in B-field using the tensor model technique to assess the hydrocarbon potential. Additional data from borehole imaging and sonic logs are critical for enhancing the evaluation of hydrocarbon potential and complements the result of the tensor model evaluation. The study was conducted to calculate the sand resistivity and sand porosity using a combination of the tensor model and the Thomas-Stieber model. The tensor model uses acquired horizontal and vertical resistivities, while the Thomas-Stieber model uses the calculated shale volume and porosity. One of the main parameters in the tensor model is shale resistivity, which upon analysis, varies across many shale sections in the well. This uncertainty is reduced by picking multiple shale resistivity values based on borehole image facies analysis. The VPVS ratio technique and Brie’s plot using compressional and shear travel time are used as a qualitative analysis that indicates the same gas-bearing interval. The tensor model calculations improve hydrocarbon saturation by a range of 4-21%, depending on sand thickness and shale volume, which increases the net to gross by more than 20%. The borehole image facies analysis helps to objectively pick the shale resistivity parameters to avoid subjective interpretation and underestimating the pay. A qualitative approach using sonic data helps to identify the potential gas-bearing interval and complement the previous tensor model interpretation. Although all interpretation methods indicate a similar gas-bearing interval that correlates with the mudlog total gas reading, the combination of the tensor and Thomas-Stieber method with image constrained shale resistivities gives the most definitive gas saturation and net pay The novelty of this study is to showcase two things. First is the application of combined tensor and Thomas-Stieber model in a laminated reservoir, with image constrained shale resistivity for improved gas saturation and net pay. The second is to highlight the use of gas-sensitive sonic data to confirm the gas saturated interval.
Saleh, Khaled (Schlumberger) | Morad, Aly (Schlumberger) | Cavalleri, Chiara (Schlumberger) | Hakim, Emad Abdel (General Petroleum Company) | Farouk, Mohamed (General Petroleum Company) | Atwa, Eslam (General Petroleum Company) | Ameen, Mohamed (General Petroleum Company) | Youssif, Youssif (General Petroleum Company) | Mamdouh, Kareem (General Petroleum Company)
Abstract Recent advancement in logging technology and data analytics allows measuring a comprehensive set of formation petrophysical properties and rock composition in cased boreholes. State-of-the-art pulsed neutron logging technology and processing algorithms record capture and inelastic elemental spectroscopy for matrix parameters, and detailed mineralogy characterization, total organic content estimation, and carbon/oxygen analysis, simultaneously with formation sigma, neutron porosity, and fast neutron cross-section. The fast neutron cross-section (FNXS) is a new formation nuclear property introduced by the advanced pulsed neutron tool that is independent of thermal and capture cross-section and highly sensitive to gas regardless of hydrogen index. Unlike thermal neutron capture cross-section, for which certain isotopes have extremely high values (such as Cl, B, and Gd), fast neutron cross-sections of all isotopes are more or less similar. Thus, FNXS is approximately proportional to atom density. Therefore, this new nuclear property has functionality similar to that of the bulk density (gamma-gamma density measurement). A local relationship can be defined to convert the FNXS into bulk density when the lithology and fluid properties are known, and calibration is possible. Otherwise, a more comprehensive assessment of bulk density can be performed by integrating FNXS with the other outputs from the slim pulsed neutron logging into a mineral solver. While solving for rock and fluid volumes from the cased-hole logs, a reconstructed bulk density may be derived in a cased-hole environment. This synthetic bulk density can be used by geophysicists to develop synthetic seismograms to properly map formation tops with surface seismic data. Since the pulsed neutron measurements follow linear volumetric law equations, they can be directly integrated into a mineral solver together with the elemental spectroscopy outputs to create a synthetic bulk density, together with the other answers. A blind comparison was done between synthetic bulk density from the cased-hole log-based mineral solver and a measured openhole density, showing a strong correlation in a three-phase fluid reservoir (gas, oil, and water). A synthetic seismogram is an essential tool when geophysicists fine-tune surface seismic data. This seismogram is developed using bulk density and compressional slowness to derive acoustic impedance, where sometimes bulk density is missing. As a result, an old approach to estimate bulk density using Gardner’s equation has certain limitations in complex environments. The new formation nuclear property that is now available in the slim pulsed neutron technology can be leveraged to provide a more robust and quality-controlled synthetic bulk density derived through FNXS integrated with the other pulsed neutron and spectroscopy outputs.
Africa is on track to becoming the world's most populous region by 2023 as growth in the continent's population surpasses that of China and India; between 2020 and 2040, one in every two births will be African, according to the International Energy Agency (IEA). The problem--and the opportunity--is that three-quarters of those new global citizens living in sub-Saharan Africa will live without access to electricity and other energy-driven staples of the modern world. "More than half a billion people [will be] added to Africa's urban population by 2040, much higher than the growth seen in China's urban population in the two decades of China's economic and energy boom," IEA noted in its Africa Energy Outlook 2019. "Growing urban populations mean rapid growth in energy demand for industrial production, cooling, and mobility," IEA analysts wrote. "The projected growth in oil demand is higher than that of China and second only to that of India as the size of the car fleet more than doubles (the bulk of which have low fuel efficiency) and liquefied petroleum gas (LPG) is increasingly used for clean cooking." With regards to gas, Africa is on track to becoming the third-largest region to feed the growth in global gas demand over the next 20 years, the IEA said (Figure 1).
Summary The nonparametric transformation is a data-driven technique, which can be used to estimate optimal correlations between a dependent variable (response) and a set of independent parameters (predictors). This study introduces a systematic methodology using the nonparametric transformation concept and the alternating conditional expectation (ACE) algorithm to estimate the effective gas permeability using conventional logs and the core data. The ACE algorithm was employed in the current work using the MATLAB® (The MathWorks, Inc., Natick, Massachusetts, USA) code and the open-source GRaphical ACE (GRACE) software (Xue et al. 1997) for deriving the optimal nonparametric correlations for predicting the permeability. The methodology was applied to a heterogeneous formation [Bahariya (BAH)] in Egypt to understand its characteristics and predict its permeability more accurately. The BAH Formation is considered one of the main sources for oil production throughout the Western Desert (WD) of Egypt. The cumulative oil production from the BAH Formation is estimated to be approximately 40% of the total WD production. The reservoir characteristics of the BAH Formation range from highly permeable to tight sandstone interbedded with shale and siltstone. It usually depicts low-resistivity and low-contrast (LRLC) log behavior. Thus, regional and accurate determination of the reservoir permeability for the different rock units of the BAH Formation across the WD is a challenge. Conventional well log data from approximately 100 cored wells and corresponding 5,500 core measurements were used to provide a regional permeability correlation that can be used in a large number of reservoirs. The methodology of this work included two main steps: Applying the nonparametric transformation technique to identify the collective log responses for deriving optimal correlation Predicting the permeability profiles using the selected log responses The model was applied to many wells that address different petrophysical characteristics of the BAH Formation. The established permeability profiles showed reliable correlation coefficients relative to the measured core data. The correlation coefficient was 0.893 for the training data points (75% of the collected database) and 0.913 for the testing data points (25% of the collected database). In addition, the mean absolute percentage error (MAPE) between the predicted and the measured permeability for the training and testing data points were 5.93 and 4.14%, respectively. Permeability prediction using ACE is compared with other techniques such as k-ϕ crossplots, multiple linear regression (MLR), Coates, and Wyllie-Rosecorrelations. This work is considered an original contribution to present regional permeability prediction correlations using the conventional well logs for reservoir characterization and simulation applications. The ACE algorithm was successfully applied to the BAH Formation and proved its capability to identify the best predictors that are required to establish a rigorous model.
At the time, producing from satellite wells a mere 5 km away was the limit of what could be practically achieved with direct hydraulic controls. Extending beyond 5 km with existing technology raised significant concerns related to making wells safe in an emergency, while the manufacture and installation of large lengths of bundled umbilicals was also technically challenging. At the same time, the water depth and hostile environment of the Magnus field made two-platform field development prohibitively expensive. The operator needed an alternative approach. As development of the solution progressed, so too did the operator's business case which came to rely on the use of the multiplexed electrohydraulic control system.
Abstract Monitoring and surveillance (M&S) is one of the key requisites for assessing the effectiveness and success of any Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) project. These projects can include waterflooding, gas flooding, chemical injection, or any other types. It will help understand, track, monitor and predict the injectant plume migration, flow paths, and breakthrough times. The M&S helps in quantifying the performance of the IOR/EOR project objectives. It provides a good understanding of the remaining oil saturation (ROS) and its distribution in the reservoir during and after the flood. A comprehensive and advanced monitoring and surveillance (M&S) program has to be developed for any given IOR/EOR project. The best practices of any such M&S program should include conventional, advanced and emerging novel technologies for wellbore and inter-well measurements. These include advanced time-lapse pulsed neutron, resistivity, diffusion logs, and bore-hole gravity measurements, cross-well geophysical measurements, water and gas tracers, geochemical, compositional and soil gas analyses, and 4D seismic and surface gravity measurements. The data obtained from the M&S program provide a better understanding of the reservoir dynamics and can be used to refine the reservoir simulation model and fine tune its parameters. This presentation reviews some proven best practices and draw examples from on-going projects and related novel technologies being deployed. We will then look at the new horizon for advanced M&S technologies.
Abstract Horizontal well technology is one of the major improvements in reservoir stimulation. Planning and execution are the key elements to drill horizontal wells successfully, especially through depleted formations. As the reservoir has been producing for a long time, pore pressure declines, resulting in weakening hydrocarbon-bearing rocks. Drilling issues such as wellbore stability, loss circulation, differential sticking, formation damage remarkably influenced by the pore pressure decline, increasing the risk of losing part or even all the horizontal interval. This paper presents an extensive review of the potential issues and solutions associated with drilling horizontal wells in depleted reservoirs. After giving an overview of the depleted reservoir characteristics, the paper systematically addresses the major challenges that influence drilling operations in depleted reservoirs and suggests solutions to avoid uncontrolled risks. Then, the paper evaluates several real infill drilling operations through depleted reservoirs, which were drilled in different oilfields. The economic aspect associated with potential risks for drilling a horizontal well in depleted reservoirs is also discussed. The most updated research and development findings for infill drilling are summarized in the article. It is recommended to use wellbore strengthening techniques while drilling a horizontal well through highly depleted formations. This will allow using higher mud weight to control unstable shales while drilling through the production zone. Managed Pressure Drilling should be considered as the last option for highly depleted formations because it will require a greater level of investment which is not going to have a superior rate of return due to the lack of high deliverability of the reservoir. Using rotary steerable systems is favored to reduce risks related to drilling through depleted formations. Precise analysis of different drilling programs allows the drilling team to introduce new technology to reduce cost, improve drilling efficiency and maximize profit. It is the responsibility of the drilling engineer to evaluate different scenarios with all the precautions needed during the planning stage to avoid unexpected issues. The present market conditions and the advancement in technologies for drilling horizontal wells increase the feasibility of producing the depleted reservoirs economically. This paper highlights the challenges in drilling horizontal wells in highly depleted reservoirs and provides means for successfully drilling those wells to reduce risks while drilling
Southeast Asian operators sit in the middle of the world's fastest growing economic region where energy demand is expected to double over the next 20 years. But this picture of growth has been juxtaposed with the region's declining oil and gas production--most of which comes from offshore fields--that has left it increasingly reliant on imports from overseas suppliers. The degree to which operators in Malaysia and Indonesia can help counter this trend was the focus of an executive panel last week at the International Petroleum Technology Conference (IPTC). While acknowledging that the region is marked by challenging geologies and mature offshore fields, the executives spoke highly of what the future holds. Several things underpin their optimism, not least of which is the region's rising demand for natural gas.