A geomechanical study was conducted for one of the drilling platforms in offshore Saudi Arabia, where several highly deviated (well inclination > 80°) development wells were planned. The main objective was to provide safe mud weight ranges and predict possible problematic depths to minimize drilling challenges like pack-off, stuck-pipe, lost in hole, over-pulls etc., which are likely due to wellbore instability. The scope of this work was restricted to the curve section of the planned wells because most of the problematic formations, comprising mainly shale and weak interbedded sand formations, are encountered in the curve section.
The operator's drilling department sought a clear understanding of the geomechanical aspects of these problematic formations to optimize the drilling plan and minimize nonproductive time. A 1D mechanical earth model (MEM) was constructed using openhole log data available from the only exploratory well drilled on this platform. The 1D MEM was further used in conducting post-drilling analyses to validate and history match events related to wellbore instability (like tight spots, pack-off etc.,) that were observed while drilling and stress-related wellbore failure as shown by the calipers.
The developed model was used for analyzing planned well trajectories and providing mud weight window limits to safely drill the highly deviated planned wells. Sensitivity analysis was performed to identify the well inclination limits to drill across the problematic zones whilst minimizing issues related to wellbore instability. The developed geomechanical model was validated using the log data acquired during drilling each of these inclined wells; the predictions from the model were in close agreement with actual observations during drilling.
The outcome of this study helped optimize the well design for upcoming wells in this field. Using the recommendations provided from this study, several highly deviated development wells were successfully drilled and completed. Apart from standard failure analysis, ‘depth of failure’ approach was also taken into account to provide recommendations on optimum drilling mud weight. Utilizing the geomechanical study, extended reach curve sections as long as 5000-ft measured depth (MD) were planned and drilled successfully without any significant nonproductive time (NPT).
Ferras, Abdelkader (PDO LLC) | Al Obeidany, Rashid (PDO LLC) | Qassabi, Nabhan (PDO LLC) | AL Aghbari, Salim (PDO LLC) | Abry, Nadia (PDO LLC) | Benmesbah, Mohamed Oukil (PDO LLC) | Benmahiddi, Samir (PDO LLC) | Radwan, Mohamed (PDO LLC) | Van Der Werff, Niels (PDO LLC) | Abdel Samiee, Rady (PDO LLC) | Mahrooqi, Mohammed (PDO LLC) | Chibani, Zied (PDO LLC)
Despite the associated waste management cost to comply with the international standards, Oil Base Mud (OBM) remains the drilling fluid of choice to drill trouble prone formations in PDO LLC, Oman drilling operations mainly through the formations of Fiqa Sharji, Nahr Umr, Khuf and Gharif in different fields of Oman. Low Toxicity Oil Base Mud (LTOBM) is exhibiting excellent well bore stability due to oil wet property, however, its high cost resulting from low aromatic base oil and associated waste management to comply with the international standards and local environmental regulations provided the impetus to conduct a feasibility study to identify an environmentally friendly and cost effective drilling fluid without impairing drilling performance. The evolvement of High Performance Water Base Mud (HPWBM) technology helped to identify a fit for purpose drilling fluid capable to deliver near OBM drilling performance with cost effective environmental compliance with local regulations.
The following tests were carried out on different cuttings samples collected from the aforementioned formations when exposed to different drilling fluids formulations:
As a result of the intensive laboratory work, an appropriate HPWBM system was selected for each formation and each field. The first fields’ trials concluded promising results with 100 % success rate on vertical wells and 50 % success rate on horizontal wells. HPWBM drilling performance was competing with OBM with significant cost reduction of 33-70 %. Further benefits, such as better zonal isolation achieved through better cement bonding to both formation and casing is worth considering.
More importantly, two wells drilled by this HPWBM were initially planned to be water injector wells and ended by being converted to oil producers after positive logging results. This is an important field proven feature for a reservoir friendly system.
This paper details the engineering works performed at PDO laboratory on testing the shaly cuttings behavior against different drilling fluids and at the field trials describing the best practices.
Recent developments in surface logging and the need for sophisticated information on reservoir content and type in the oil industry have led to the availability of real-time advanced fluid solutions assisting in informed decisions while drilling.
The objective of this study was to identify possible fluid contacts and acquire PVT quality sample data while drilling Paleozoic formations. This is accomplished by extracting and analysing formation gas from the drilling fluid employing the Advanced Formation Gas Extraction System for formation evaluation with a high-resolution chromatograph.
The Advanced Formation Gas Extraction System provided consistent flow and heated mud and maintained constant temperature conditions. Thus, it provided an accurate chromatographic breakdown of the formation gas extracted from the drilling fluid at surface. The chromatograph was able to detect the hydrocarbons from the light to heavy factions, methane (C1) to pentane (C5), and also extended the detection range to include the dominant C6, C7, C8, aromatics and lighter alkenes.
Gas ratio analysis of the detected hydrocarbon components enabled us to evaluate the reservoir fluid content and to identify and characterize the formation fluid and possible fluid contacts.
The results, validated by correlation and comparison with other data such as wireline logs, well tests and PVT results assisted in the characterization of lithological changes, possible fluid contacts, vertical fluid differentiation in multi-layered intervals, and drill bit metamorphism (thermal cracking) effect.
The comparison between surface gas data analysis and PVT data confirms the consistency between the gas show and the corresponding reservoir fluid composition.
Mudlogging services provide one of the earliest data available while drilling. The acquisition of gas in mud data while drilling for safety and geological surveillance is an almost universal practice.
First introduced commercially in 1939, these mobile laboratories carried little more than a coffee pot, a microscope for examining formation cuttings and a hotwire sensor for detecting the amount of hydrocarbon gas encountered while drilling.
Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohammed (King Fahd University of Petroleum & Minerals) | Ali, Abdulwahab Z. (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals)
Today's economic conditions emphasize the need for better engineering designs in drilling, well completion, and reservoir production operations. A knowledge of the mechanical behavior of reservoir rocks is important in connection with wellbore stability problems, fracturing operations, subsidence problems and sand production problems. To carry out any aforementioned operations, continuous profiles of rock mechanical parameters are needed. Retrieving reservoir rock samples throughout the depth of the reservoir section and performing laboratory tests on them are extremely expensive as well as time consuming.
Consequently, rock failure parameters are often correlated with geophysical well logs such as bulk density, compressional and shear wave velocities, which may result in continuous profiles of failure parameters throughout the depth of the well section. However, these estimations not truly represent the reservoir in-situ stress-strain condition. Therefore, failure parameters are estimated from empirical correlations.
Most of the previous correlations were developed using linear or non-linear regression techniques. Artificial intelligence tools once optimized for training can successfully model highly complex and non-linear relationship between different well logs as inputs and failure parameters as output. Therefore, the objective of this paper is to accurately predict the failure parameters (Angle of internal friction and Cohesion) of the rock by using basic geophysical well logs namely; bulk density, neutron porosity, compressional, and shear wave travel times, from three artificial intelligence techniques namely; Adaptive Neuro Fuzzy Inference System (ANFIS), Support Vector Machine (SVM) and Functional Network (FN).
The data used in this study were obtained from more than 10 wells located in giant carbonate reservoir. A comparison between the predicted failure parameters by the proposed models with actual laboratory measured data reveals that new proposed model predicted with significantly less average absolute percentage error (AAPE) and high coefficient of determination (R2).
The developed technique can be useful for geo-mechanical engineers to determine continuous failure parameters profiles throughout the desired depth, when no laboratory tests are available.
Successful exploitation of shale reservoirs largely depends on the effectiveness of hydraulic fracturing stimulation program. Favorable results have been attributed to intersection and reactivation of pre-existing fractures by hydraulically-induced fractures that connect the wellbore to a larger fracture surface area within the reservoir rock volume. Thus, accurate estimation of the stimulated reservoir volume (SRV) becomes critical for the reservoir performance simulation and production analysis. Micro-seismic events (MS) have been commonly used as a proxy to map out the SRV geometry, which could be erroneous because not all MS events are related to hydraulic fracture propagation. The case studies discussed here utilized a fully 3-D simulation approach to estimate the SRV.
The simulation approach presented in this paper takes into account the real-time changes in the reservoir's geomechanics as a function of fluid pressures. It is consisted of four separate coupled modules: geomechanics, hydrodynamics, a geomechanical joint model for interfacial resolution, and an adaptive re-meshing. Reservoir stress condition, rock mechanical properties, and injected fluid pressure dictate how fracture elements could open or slide. Critical stress intensity factor was used as a fracture criterion governing the generation of new fractures or propagation of existing fractures and their directions. Our simulations were run on a Cray XC-40 HPC system.
The studies outcomes proved the approach of using MS data as a proxy for SRV to be significantly flawed. Many of the observed stimulated natural fractures are stress related and very few that are closer to the injection field are connected. The situation is worsened in a highly laminated shale reservoir as the hydraulic fracture propagation is significantly hampered. High contrast in the in-situ stresses related strike-slip developed thereby shortens the extent of SRV. However, far field nature fractures that were not connected to hydraulic fracture were observed being stimulated.
These results show the beginning of new understanding into the physical mechanisms responsible for greater disparity in stimulation results within the same shale reservoir and hence the SRV. Using the appropriate methodology, stimulation design can be controlled to optimize the responses of in-situ stresses and reservoir rock itself.
The critical micelle concentration (CMC) of surfactants represent the concentration at which surfactant monomers start to form aggregates in order to minimize the energy of the electrostatic and hydrophobic interactions of the system. At this concentration, any additional surfactant molecules are not available at the interface but in aggregates in the bulk of the solution. A measure of CMC for a field surfactant gives an indication of the concentration needed for its effectiveness as an enhanced oil recovery (EOR) agent. This has been shown to be dependent on several factors including the nature of the brine, temperature, and ionic species strength. As such, for field applications, CMCs need to be measured for the particular environment that the surfactant will be used in.
In this work we have measured the CMCs for three types of EOR surfactants. The Du Noüy ring method was used with an automatic dispenser to dilute and measure surface tensions of the various surfactants at different temperatures and in different field brines. The effect of other chemical species, especially polymer was also investigated. Of the three surfactants studied, the betaine surfactant showed the lowest CMC in both injection seawater and field produced brine. It also out-performed the others in temperature stability for all types of brines. The other two surfactants were an amine oxide and an alpha olefin sulfonate. For the field brine conditions, the amine oxide proved to be the poorer performer in terms of CMC while the anionic alpha olefin sulfonate was close to the amphoteric surfactant.
Determination of CMC for real field brine conditions and at elevated temperatures provides a good insight into the performance and potential of different surfactants. Coupled with other tests like phase behavior and interfacial tension (IFT) measurements, very quick decisions can be make about the efficacy of surfactants for field application.
Drilling fluid is the life line of safe and economic drilling operation to explore oil and gas resources from the earth's crust. However, it is also the root cause of various mud related drilling problems such as shale-drilling fluid interactions, borehole instability, loss of circulation, differential pipe sticking, etc. Differential sticking is one of major drilling problems that is very common when passing through a sticking prone high permeable zone. It is one of the major items of non-productive time that increases the total drilling cost dramatically, especially if there is a delay in recovering a stuck pipe. Moreover, delay or inability in recovering a stuck pipe may lead to other drilling problems leading to abandonment or side tracking of a well. Hence, every step should be taken to recover a stuck pipe as soon as possible.
One of the most effective strategy for quick recovery of a stuck pipe is the use of a highly efficient and rapidly acting spotting fluid to damage, degrade and destroy mudcake-pipe sticking bonds as quickly as possible to release the stuck pipe easily from the mudcake matrix. This dictates quick laboratory evaluation of various spotting fluids available to identify the best spotting fluid for a particular mud and mudcake composition. As the chemistry of the mud additives and the deposited mudcake materials influence the performance of a spotting fluid, it is highly recommended to evaluate the de-bonding, degrading and destructive potential of a spotting fluid for a particular mudcake composition to select the superior and reject the inferior. However, there is no API or any other industry method that can be used for quick screening of various spotting fluids available to the industry to select the most efficient one for a particular stuck pipe rescue operation. This paper describes a dedicated operating software driven novel laboratory method for quick screening and reliable prediction of the performance of various spotting fluids to demonstrate the suitability of the method and test apparatus for oil and gas field application.
Experimental results indicate that the newly developed method and test apparatus can consistently and precisely predict the performance of various spotting fluids and mudcake compositions to select the most suitable spotting fluid for a particular rescue operation. It provides useful guidelines and a practical decision making tool for the drilling and mud engineers and the consultants for quick and easy recovery of stuck pipe from the mudcake matrix. The method and apparatus will also play an important role in the development of a new generation of high performance spotting fluids to overcome current and future challenges associated with differential pipe sticking problems.
In this work, an elastic carbon composite, a new category of high-pressure/high-temperature (HPHT) seal material, was developed and its successful application in downhole valves is discussed to demonstrate how it could address sealing challenges in HTHP and sour wells exploration.
As conventional oil and gas resources decline, exploration and production (E&P) activity increasingly involves operations in extreme HPHT conditions and corrosive sour environments (high in H2S and CO2), posing tremendous challenges on almost all aspects from drilling to completion and production. One of these challenges is developing reliable seals for various kinds of downhole valves, e.g., safety valves, chemical injection valves, pressure relief valves, etc., that must withstand HPHT and sour environments and must work under frequent impact and wear caused by operation or sands from downhole fluids. Under HT conditions (usually above 500° F), current valve seals made of plastic or rubber are no longer suitable, because the material loses its mechanical strength and becomes very soft. Therefore, these seal can easily extrude and fail under pressure. Metal-to-metal seals may perform better in HPHT conditions, but they have a very high failure rate due to low elasticity and high metallic hardness‥
To address this issue, an elastic carbon composite, a new category of HPHT seal material, was developed. Material tests show that this novel carbon composite material has excellent thermal stability up to 1,000° F and strong resistance to impact and wear. This paper discusses the material property of this novel elastic carbon composite. The application of the material in a chemical injection valve is also be provided as an example to show how this new composite addresses downhole seal challenges for valve applications.
The novelty of this work is developing a new seal material that could enable downhole valve work at extreme HPHT conditions. Related knowledge and information of this work would benefit engineer in developing new technologies for various downhole valve tools.
Alwazeer, Abdullah (Petroleum Development Oman L.L.C.) | Rojas, Luis Vargas (Petroleum Development Oman L.L.C.) | Marin, Antonio Andrade (Petroleum Development Oman L.L.C.) | Mackay, Angus (Petroleum Development Oman L.L.C.) | Rady, Haytham (Petroleum Development Oman L.L.C.) | Salhi, Khalid (Petroleum Development Oman L.L.C.) | Parada, Dimas Lopez (Petroleum Development Oman L.L.C.) | Habsi, Amur (Petroleum Development Oman L.L.C.) | Shaqsi, Khadija (Petroleum Development Oman L.L.C.) | Abdurrahman, Shehu (Petroleum Development Oman L.L.C.) | D'Amours, Kevin (Petroleum Development Oman L.L.C.)
Enhanced Oil Recovery (EOR) methods are on the rise and Petroleum Development Oman (PDO) has successfully embarked on several projects including thermal recovery. Thermal EOR operations require rapid response and adaptation to the dynamic thermal conditions inherent within the reservoir. The challenges associated with Cyclic Steam Stimulation (CSS) necessitated a creative solution to maximize recovery and improve well management. A fit for purpose algorithm was developed to add flexibility while operating the well in combination with the Variable Speed Drive (VSD). An automation algorithm was developed to optimize oil recovery and accelerate peak oil throughout the CSS production cycle. This algorithm maximized inflow potential by creating a low fluid level above the pump and maintaining near pumped-off conditions. The project was named Beam Lift Auto Delivery Evolution (BLADE).
Live control of the pumping unit provides equipment safe guarding while ensuring continuous operation within the defined envelope. This is achieved by applying real time assessment of pump fillage and temperature conditions. This approach optimized production while maintaining adequate fillage, thereby increasing operations efficiency and prolonging pump life.
Within a thermal environment, enhanced automation provides the additional advantage of steam break through mitigation. The mitigation improves pump efficiency and prevents pump gas lock. This algorithm provided a unique advantage within this thermal operation by adapting to varying viscosities impacting inflow throughout the production phase.
Thermal CSS requires continuous monitoring and rapid reaction time to adapt to the dynamic conditions inherent to the CSS operation. The BLADE project has demonstrated that utilization of carefully designed logic in conjunction with robust field steaming strategy, not only improved field recovery but also significantly reduced manpower demand by 20% and decreased the total EOR cost.
The vision was conceived in the early stages of “A” East development. The intended plan was to develop an automated self-optimizing and self-adjusting pump control, bypassing the manual optimization typical of field operations. The operational complexity of this thermal field deemed the standalone controller too basic and inflexible to allow for well production testing, this resulted in the development of a programmable self optimizing logic utilizing VSDs to enhance well operation. The dynamic nature of CSS requires aggressive optimization and mitigation from ever-changing operational conditions associated with this thermal recovery process. This paper will focus on the optimization process and the advantages of implementing automation in a thermal CSS producing field.
This paper presents the results from a successful field test of a real-time portable sensing system for fluorescent nanoparticle tracers directly from the well head, reducing previous sample processing and detection time by over 99%. In 2014, the first oil industry nanoparticle tracers (ADOTS), were injected at a tertiary produced reservoir to demonstrate for the first time, the ability of nanoparticles to successfully traverse Arab-D reservoir rock. The ADOTS proved to be remarkable reservoir agents showing excellent stability and mobility and are still being recovered more than two years later. ADOTS are inexpensive to produce and can be prepared at the well site. ADOTS sample collection and processing was performed manually, as are most tracer samples and results were obtained at a minimum of 30 hours after sample collection due to the time consuming laboratory processes needed in order to analyze the water with sophisticated instruments for accuracy. To address this issue, a portable real-time sensing system was developed to collect, process and analyze samples directly from the well head in about 5 minutes and is capable of measuring fluorescent tracer concentration at the ppb level. The portable sensing system, was tested, directly from a wellhead currently producing fluorescent nanoparticle tracers from a related injection test. The system was able to process, analyze and report accurate data in about 5 minutes, demonstrating a >99% increase in process efficiency and eliminating the large cost of standard chemical tracer processing. This prototype system provides a revolutionary breakthrough in reducing the time and money associated with detecting fluorescent tracers used for decades in the industry. For the first time, a fluorescent tracer can be detected at the well site in real time using inexpensive, portable equipment.
The value of tracer studies has been evident and widely acknowledged in the oil industry for decades. Both chemical and radioactive tracers have been an industry standard for years. These tracers can be used to map the flow path of oil recovery processes from injection to production. This method can determine fractures and super k zones along the path of the injection, or establish that an injector is not connected to any producers. Some immediate drawbacks to using chemical and radioactive tracers are the high cost of materials, time consuming and multifaceted analytical detection methods, lack of robustness in reservoir conditions, special health and safety requirements and disposal of spent material (Fink, 2003). Proper sample collection and handling are also key factors for these types of tracers. Failure to follow the specific techniques required to preserve sample integrity or failing to analyze the sample before the designated holding time can render the tracer test useless (Du, 2005). Sampling a typical chemical tracer from the production line and preparing and analyzing it can take anywhere from 2 weeks to a month to receive lab results from a typical contractor. Radioactive tracers confound these problems further requiring enhanced safety standards, processing work and disposal methods.