Hydrocarbons are trapped at great depths with pressure and temperature higher than surface conditions which would vary depending on reservoir properties. When the well is set on production, these hydrocarbons travel through the wellbore over reducing geothermal and formation pressure gradients. Hence, at shallower depths the temperature drops below the cloud point and sometimes, below pour point of crude thus creating an ambient temperature for the formation of wax and deposition of paraffin on the inner side of production tubing.
It has been observed that when hot fluid passes through a pipe which is covered by a continuously circulating hot water bath, the temperature difference of the fluid at surface outlet and sub-surface reservoir is reduced to a minimal value. This paper therefore proposes a practical application of such heat transfer within a wellbore for passively solving major industrial issues of paraffin depositions. The idea lies in minimizing the heat losses, which can be effectively done by insulating the inner side of the casing so that the annulus and fluid flowing within the tubing is isolated from exterior losses. According to the First law of Thermodynamics the fluid flowing within the tubing will experience reduction in thermal gradient. These loses can be compensated by injecting hotter brine through a pipe at the bottom of the annulus, which is isolated, using production packer. Further, circulating hot fluid in the annulus would result in isothermal heating of the fluid flowing through the tube which would minimize the heat loss across tubing, causing an increase in temperature of fluid at the surface above pour point. Several researchers have put forth heat transfer equations across the tubing's, annulus, insulator, casing, cement and the formation which can be used to calculate the overall heat transfer coefficient and thus, the amount of heat losses. Quartz sensors placed at the bottom of a wellbore would detect bottom borehole temperature based on which the injection temperature of fluid can be manipulated. The entire process can be automated by applying an artificial intelligent system which would monitor, control and respond. This method would increase the capex but would decrease the operating cost thus leading to an increase in the life of the well.
The key objective of this study was to develop a high resolution wellbore stability model for planned highly inclined development wells of an ultra-deepwater field through integrating geological, geophysical, petrophysical and drilling data to design optimized drilling mud weight window.
This study describes a customized high resolution wellbore stability modelling process for development wells in ultra-deepwater setting, where shale and sandstone have different pore pressure and stress magnitudes. Un-calibrated and calibrated seismic velocities along with offset well data were used to generate the high resolution pore pressure model for the overburden shale section. Laboratory based geo-mechanical tests, petrophysical logs and offset well events were integrated for the estimation of sub surface stresses and rock mechanical properties for overburden shale and sandstone. Subsequently, separate wellbore stability model was built to estimate the shear failure gradient for overburden shale and sandstone.
This study suggests that the mud weight (MW) window in the overburden is primarily governed by two parameters – (i) sand-shale pressure equilibrium state, and (ii) stress anisotropy. The intervals where the sand and shale are not in pressure equilibrium state (i.e. shale pressure > sand pressure), the minimum MW requirement is defined by either pore pressure or shear failure gradient (SFG) of shale formation. Whereas, maximum limit is marked by fracture gradient of relatively less pressured sand formation. Therefore, in such intervals mud weight window becomes much narrower (~1 ppg) than those intervals where sand and shale is in pressure equilibrium (~1.6 ppg). This study also highlights the increase of minimum MW requirement (SFG) in some intervals having relatively higher stress anisotropy. The minimum MW requirement within the main reservoir section having thin intra-reservoir shale is controlled by the SFG of the sand formation, as strength is lower in the reservoir sand than intra-reservoir shale. Results show the importance of high resolution modelling in order to capture pressure uncertainty, thin sands, sand/shale pressure equilibrium state, stress anisotropy and its effects in defining the optimum mud weight window. Based on analysis, further risk zonation was done to highlights intervals prone to wellbore collapse and mud loss.
This paper illustrates how the integrated high resolution wellbore stability modeling would help in optimum mud weight planning for highly deviated / horizontal wells to minimize the drilling risks and non-productive time (NPT), especially for challenging field development settings (deepwater, ultra-deepwater, high stress, High pressure High temperature).
Wellbore integrity is very critical in oil and gas industry and needs to be maintained through the entire cycle of well's life. The most important item for well integrity is to set cement between two casings or between casing and formation. A good cement job provides isolation and protection for the well and a poor cement job can have cracks and allows corrosive fluids to migrate through micro channels.
Downhole casing repair is a common workover operations worldwide, especially in wells that have been producing over number of years. It is very challenging to control corrosive fluid migration which slowly corrodes casing and tubing over time. An innovative epoxy resin formulations has been developed and tested in the field to repair casing leaks which is extremely easy to handle and very economical. A cost-effective workover program can be developed and implemented depending on the severity of the leak.
The improved approach of using innovative resin can be used by mixing with cement blends to repair major casing damage and can also be used as standalone application to fix minor leaks. The system maintains extremely good rheological properties even when mixed with cement. The system has ability to withstand high differential pressure and is also resistant to acid, salts, hydrocarbons and most importantly various corrosive liquids. The precise application is determined by measuring the injectivity of the well. In the low injectivity wells, only epoxy resin solution will be spotted and repair the damaged casing. In the high injectivity wells, the chemical will be mixed with cement and completely seal the damaged zone. The chemical will enhance the mechanical properties of the cement and will be more resilient to extreme down-hole condition.
The paper will emphasize the added value and potential of the method in restoring the casing integrity. The paper will also discuss the laboratory test reports and application which will highlight effective and economical outcome.
Saha, Sankhajit (Baker Hughes, a GE company) | Gariya, Bhuwan Chandra (Hindustan Oil Exploration Company Ltd) | Panda, Debabrata (Hindustan Oil Exploration Company Ltd) | Perumalla, Satya (Baker Hughes, a GE company) | Podder, Tuhin (Baker Hughes, a GE company) | Thanvi, Shrikant (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company)
Drilling through the thick shale sequence (Oligocene to Paleocene age) of Cauvery offshore showed severe wellbore instability in the past due to incompatible mud program that increased overall operational cost. While new high-angle sidetrack development wells had been planned, three major challenges need to be addressed. First, proper mud weight recommendation for preventing mechanical instability; second, introduction of a cost-effective mud system preventing time-sensitive failure; and finally, mitigating the environmental impact factor of the mud system.
Geomechanical modelling and Hole Stability analysis had been performed based on available dataset. An optimized mud weight (MW) program was developed based on the analysis. Considering the time-dependent failure characteristics of the shale and overall cost effectiveness, just modifying the mud weight does not address all of the challenges delineated above. Consequently, special "high-performance water-based mud system (HPWBM)" was designed instead of oil-based mud (OBM). This HPWBM was formulated based on the nature of shales encountered. While drilling, real-time geomechanics further facilitated controlled drilling conditions and optimized the mud program.
The well-based geomechanical model indicated a hydrostatic pore pressure gradient in the region. The relative magnitude of three principle stresses showed a normal fault stress regime and maximum horizontal stress (SHmax) azimuth appeared to be nearly aligned to the N-S direction. Hole Stability analysis showed that a minimum of 12 ppg mud weight was required to drill the 8½" section. The sidetrack holes had a maximum inclination of 75 to 77 degrees. Different polymers and bridging agents were added to prepare the customized HPWBM in order to address shale instability and formation damage due to overbalance. Real-time monitoring during drilling operation utilized logging while drilling (LWD) log data, drilling parameters and mud logging data to promote smooth drilling operations. Through systematic planning and execution, the high-angle sidetrack holes had been drilled with zero non-productive time (NPT) in terms of well bore stability. More than 50% cost reduction was achieved on the mud system.
An integrated solution that includes pre-drill geomechanics, HPWBM system design and real-time well monitoring helped to reduce the risks due to model uncertainties while drilling high angle wells through the thick shale section. This approach helped to reduce significant operational cost with an improved success rate.
The 2015 oil price downturn and future uncertainty in the industry have resulted in Malaysia Oil and Gas Regulator PETRONAS (MPM) taking a more proactive role in driving Malaysian Petroleum Arrangement Contractors (PACs) to maximize lifecycle value from their well stock. Key focus areas include streamlining review processes, reducing well cost, maximizing production from active wells and reactivating idle wells, reducing failures from well activities, driving value driven surveillance and promoting low cost well abandonment. This paper will focus on how the objective & value driven approach by PETRONAS MPM have resulted in business performance improvements at the national level through proactive and effective well value maximization throughout field/well lifecycle, from exploration stage down to the decommissioning and abandonment stage.
With the promotion of oil and gas development around the world, the exploration scope has been gradually extended to complicated geological reservoirs, such as deep or ultra-deep, unconventional, deep-water reservoirs, and lost circulation and wellbore instability have been becoming the most serious problems, which puts forward higher requirements on the drilling fluid technology. In order to solve these technical problems, the wellbore strengthening mechanism, tight fracture plugging methods and simulation experimental method for drilling fluids were studied respectively in this paper. Firstly, the wellbore strengthening mechanism of the stress cage method that improves wellbore pressure containment was firstly investigated based on ABAQUS finite element modeling analysis. It was found that wellbore pressure containment could be improved by enhancing plugging performance of drilling fluids to plug and prop natural or induced fractures to eliminate fracture propagation and increase hoop stress. The key performance of loss prevention materials has been proved to play a prominent role to achieve wellbore strengthening effect and strengthen the wellbore. According to the basic principle of "force-chain" in granular matter mechanics, the key fine technical indices were proposed to evaluate the particle strength, particle resiliency and surface friction of loss prevention materials. Meanwhile, the corresponding physical model of tight fracture plugging zones was established to reveal the tight fracture plugging mechanism at micro scale and the optimization method of tight plugging drilling fluids was also put forward, and it was concluded that using reasonable particle type, particle size distribution and concentration control, rigid particles, resilient particles and fibers were synergized to plug fractures, so as to form tight pressure containment plugging zones with a strong force chain network and greatly improve the wellbore pressure containment. The novel experimental apparatus for evaluation and dynamic simulation on the plugging characteristics of drilling fluids was developed, which could simulate the loss and plugging process of fractures with different openings under different formation pressures and temperatures.
The basic objective of real-time pore pressure (RTPP) services is to maintain the equivalent static density (ESD) and equivalent circulating density (ECD) within a desired mud weight (MW) window. This paper will present a new workflow to differentiate between supercharging in low-permeability, limited lateral extent sands, and genuine elevated pore pressure; ultimately preventing unwarranted MW increases that might either result in premature termination of the section or induce losses.
In a typical workflow, log-derived models are used to compute the pore pressure (PP) in shales. These models are calibrated with drilling events and prompt formation pressure-while-drilling (FPWD) pretests in sands. However, in the Gulf of Mexico (GoM), sub seismic sand lenses are susceptible to supercharging; sometimes manifesting as an event gas peak. Moreover, using these gas events to determine supercharging have proven unreliable as they do not systematically occur. A novel workflow using time-lapse FPWD measurements, incorporating the acquisition environment, and the ability to circulate drilling mud at different flowrates to iteratively demonstrate the presence of supercharging has been developed.
A common scenario is presented from a deep water well in the GoM in which both RTPP and FPWD services were run. As drilling progressed, the shale PP computed from the sonic logging-while-drilling tool was repeatedly validated with FPWD measurements. However, then a pretest conducted across an underlying sand showed PP value slightly higher than the computed shale PP. Based on conventional methodology, this condition would trigger a MW increase. Following regulatory requirements, ESD should be in a specified range above the confirmed PP. If the MW was increased further, the resulting ECD would be near the last casing shoe leak off test value, compromising wellbore integrity. If the flow rate was reduced to control the ECD, then wellbore cleaning would be compromised. A departure from the previously observed sand-shale PP equilibrium was unexpected and supercharging was suspected in this underlying sand. Clear evidence of supercharging was demonstrated by employing an iterative sequence of four repeated pretests with parameter adjustments. Experimental data were obtained and showed that no MW increase was required. Based on these results, the RTPP model was adjusted accordingly, and drilling continued without any problems to the planned section total depth.
The presence of potentially supercharged sub seismic sand lenses complicates PP calibration. This new workflow is proposed to identify supercharging in these sands; thus, minimizing unwarranted MW increases, which could either result in premature termination of the section or induce losses. Either of these results could lead to operation cost overruns and extra casing and liner runs. The efficiency of the new workflow is demonstrated by the safe and successful drilling of a Deepwater prospect.
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.
Xu, Chengyuan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Yan, Xiaopeng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Kang, Yili (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | You, Lijun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhang, Jingyi (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lin, Chong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Jing, Haoran (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Plugging natural fractures with lost control materials (LCMs) is the common method to prevent foramtion damage and control fluids loss in In naturally fractured reservoir. The plugging zone strenfth stability is critically important for maintaining long-term plugging quality. Surface friction coefficient (SFC) is proposed as an important parameter for the selection of LCMs based on based on granular matter mechanics and the instability of plugging zone. The force chain network with specific geometry is the basis of the plugging zone strength and supporting external load. The likelihood of shear failure can be increased by decline of SFC. And high strength of force chain can not be formed and it can relatively easy to be broken even if a small shear is applied. Effects of LCMs particle size distribution, circulation abrasion, LCMs combination, working fluids infiltration, and high temperature aging on friction behaviors are analyzed for LCMs with high SFC selection. Results show that the average SFC shows a decreasing trend with the particle size reduction and the difficulty of particle dislocation decreases with the particle size reduction. For deep naturally fractured reservoirs, particle size will degradate due to long-term drilling fluid circulation in the wellbore, thus affecting the plugging effect of drill-in fluid. The mixture of elastic material and fiber into rigid material increases the SFC and elastic material contributes most to the increasing the SFC. The SFC decreases under the condition of fluids infiltration, and the SFC show a higher decline in oil-based condition. The high-temperature aging makes the edge of the organic rigid material more smooth, which reduces its SFC.
Wang, GaoCheng (PetroChina Zhejiang Oilfield Company) | Zhao, Chunduan (Schlumberger) | Liang, Xing (PetroChina Zhejiang Oilfield Company) | Pan, Yuanwei (Schlumberger) | Li, Lin (PetroChina Zhejiang Oilfield Company) | Wang, Lizhi (Schlumberger) | Rui, Yun (PetroChina Zhejiang Oilfield Company) | Li, Qingshan (Schlumberger)
Huangjinba shale gas field is located at the south edge of the Sichuan Basin. It has very complex structures, in situ stresses and natural fracture corridors in comparison to adjacent areas in the Sichuan Basin. In recent drilling campaigns, drilling risks have caused some wells to fail in reaching their planned total depth, eventually failing to deliver cost-effective gas production. In order to mitigate drilling risks, e.g. mud loss, collapse, stuck, hang up, gas kick, effective drilling risk prediction is an urgent challenge to address. Integrating quantitative drilling risk prediction methods with qualitative methods could increase the prediction accuracy and avoid or mitigate the drilling risk during the well deployment stage.
In this project, multiple seismic attributes were used to predict natural fracture distributions which qualitatively indicated the locations where drilling risks were likely occur. Comprehensive geophysical characterization was performed to identify natural fracture zones and patterns, and their mechanisms were validated by analyzing regional geological and tectonic evolution.
Image log data was then integrated into the natural fracture distribution prediction from seismic to build a DFN (Discrete Fracture Network). This combination of the DFN predicted from seismic data plus quantitative image log information allowed improved accuracy in the prediction of drilling risks.
Following this, natural fracture stability was analyzed by building a 3D geomechanics model in order to predict drilling complex qualitatively. A full field 3D geomechanics model was built through integrating seismic, geological structure, log and core data. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. 3D pore pressure prediction was conducted using seismic data and calibrated against pressure measurements, mud logging data, and flowback data. The discrete fracture network model, which represented multi-scale natural fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural fracture systems.
From these models, a drilling map which quantitatively indicated the depth where drilling risk such as mud loss, gas kick, etc. occurred was created along the well trajectory.
This paper presents the highlights and innovations in seismic multi-attributes analysis and full-field geomechanics modeling which integrate qualitative and quantitative methods for drilling risk prediction.