In the present paper, numerous stuck pipe events were carefully studied in wells drilled in the Kingdom of Saudi Arabia between 2013 and 2014. Stuck pipe events were analyzed per different hole sections (from 34 in. to 5 7/8 in.) and it was noted that overall the number of stuck pipe events were less for the top hole sections. Therefore, the focus of the study was to evaluate the utilization and effectiveness of Drilling Jars in the top hole sections 34″, 28″ and 22″ during stuck pipe events.
The data was collected from Saudi Aramco Stuck Pipe database and limited to new wells, a total of 42 fields and 1026 wells were reviewed. After that, each stuck pipe event was classified according to field name and to the respective hole size where the incidents occurred. A detailed and comprehensive study was conducted for each stuck pipe incident independently, reviewed daily drilling reports and determined the utilization of the Drilling Jars as well as the effectiveness to free the drill string during the stuck pipe incidents.
Classifying the stuck pipe events and analyzing the results, showed that the effectiveness of Drilling Jars in the top hole sections was uncertain. For the 34″ and 28″ hole sections, the effectiveness of Drilling Jars was minimal. For the 22″ hole sections, it showed higher number of utilization and effectiveness. The study concluded that the use of Drilling Jars in the 34″ and 28″ hole sections were ineffective, therefore it was recommended to eliminate the use of Drilling Jars for the respective hole sections across drilling operations in KSA. This decision will result in significant savings, and help to free up service provider resources for use in other hole sizes.
The research became a useful reference in defining the utilization and effectiveness of Drilling Jars across Saudi Aramco Operations. Drilling Engineers are encouraged to optimize the use of drilling equipment in the bottom-hole assembly, to improve efficiency and reduce drilling costs.
With the onset of water production, mineral scale deposition appears in the oil and gas wells. The scale deposition in wellbores and flow lines is a universal challenge that has to be addressed with technical and economical effectiveness. Efforts are ongoing to effectively inhibit the scales or remove them through chemical or mechanical means.
Kuwait Oil Company is planning to improve the production to 4.0 MM BOPD by the year 2020. In this pursuit, all the possible efforts are made to increase production including application of new technology in drilling, completion, well production and facilities. One of the key aspects of production improvement from individual wells is to avoid any obstruction in the wellbore, wellhead and flow lines that might affect the smooth flow of hydrocarbons. This includes the augmented steps on eliminating mineral deposition from wellbore and flow lines.
The wells are suffering from frequent scale deposition in wellbore and flow lines. Usually these problems are mitigated by using strong acid. However, due to maturing of field the wells are generally completed with ESPs. When acids like HCl are used, these ESPs are corroded severely adding extra cost of workover and production loss. This challenge is driving the operators to use less aggressive chemicals that remain environmentally friendly and can maintain the integrity of submersible pumps, metallurgy of the flow lines and other components.
To meet this challenge, various chemicals were evaluated through laboratory tests and case histories. The chemical composed of Glutamic acid was selected for the first pilot. The pieces of tubular and other well components suffering from scale deposition were tested in the lab and the results were found to be highly encouraging. Based on this a pilot campaign was initiated with a batch of eight wells to treat wellbore and flow lines. All the treatments were found highly successful. Due to this treatment, the daily production has been improved to 5,000 BOPD without any extra activity such as replacement of ESP or flow line tubing due to corrosion.
The paper presents the technology evaluation process, lab testing and field trial results.
The use of new digital technologies have become an imperative for oil & gas companies seeking to improve the way they do business. In this paper, a framework is presented for the strategic use of digital technologies for new field development projects. The benefits of introducing the right technology at the right time is identified across the life of field. There are six areas during field development where a digital strategy must be executed: subsurface analysis & modeling, drilling & completions, production operations, reliability & maintenance, procurement & supply chain management, and general business operations.
A case-study based approach is used based on large projects executed in recent the past where digital technologies were planned and included during early field development. The paper identifies the areas and points during field development to include different digital technologies where the business impact is maximum and capital and operational expenditure is minimum. This was done by identifying technologies across two areas: (a) technologies to enable the execution of the mega-project; and (b) technologies that form part of the facilities for operations during life of field. It was found to be optimum to link the digital strategy during the engineering and design stages, and during the issue of contracts for commissioning facilities. This allowed the field to build a digital ecosystem which will help them prepare for a digital future by enabling readiness for advancements in the areas of analytics, global mobility, and automation. Oil and gas companies obtain a chance to gain competitive advantage through digital infrastructure and software applications when applied at the right time during field development.
Mund, Bineet (Cairn India Ltd.) | Sharda, Ruchika (Cairn India Ltd.) | Das, Amlan (Cairn India Ltd.) | Somasundaram, Sreedurga (Cairn India Ltd.) | Bhat, Sudeep (Cairn India Ltd.) | Sabharwal, Varad (Cairn India Ltd.) | Gupta, Abhishek Kumar (Cairn India Ltd.) | Shankar, Pranay (Cairn India Ltd.)
Raageshwari Deep Gas (RDG) Field in the Southern part of Barmer Basin is a tight gas-condensate reservoir composed of a thick volcanic unit overlain by volcanogenically-derived clastic Fatehgarh formation. This tight reservoir hosts significant gas reserves and is being successfully exploited with the implementation of multi-stage hydraulic fracturing. For optimum hydraulic fracture stimulation, a clear understanding of the geomechanical properties of the reservoir and its seamless integration with petrophysical interpretation is of paramount importance to achieving long-term sustainable well performance. The key geomechanical factors in hydraulic fracturing of deep volcanic reservoirs form a niche subject as opposed to the widely published unconventional shale plays. This paper illustrates the workflow developed for construction of 1D-Geomechanical model in tight volcanics and its application for selecting perforation intervals and designing of frac jobs; its validation through diagnostic fluid injection, execution of hydraulic fracturing jobs and associated challenges.
The one dimensional Geomechanical model integrates basic petrophysical logs, dipole sonic data, rock mechanical tests on core, processed image log data with break out analysis, regional tectonic history, existing natural fracture evidences and drilling data. Most importantly, the model is calibrated with field test data such as diagnostic fluid injectivity test (DFIT), step rate test (SRT) and mini-frac data. The workflow involves estimation of rock mechanical properties (Young's modulus, Poisson's ratio, uniaxial compressive strength) based on logs and calibration with core data and documented analogues. The next step is modelling of stresses in the field for identification of current stress regime. Integration of failure models with wellbore image data provides the understanding of maximum horizontal stress. Basic log data is used for estimation of over burden and pore pressure. Calibration of pore pressure is carried out from the DFIT data. The third step involves the assimilation of rock strength model with stress model to estimate minimum horizontal stress. In a geologically complex setting with multiple histories of tilting and faulting, tectonics plays an important role in the existing stresses. All these variables are captured and validated with field test data to construct a useful geomechanical model.
As part of the recently concluded hydraulic-fracturing campaign, the 1D-Geomechanical model was successfully applied to identify approximately 125 fracture stages in 20 wells for multi-cluster hydro-fracturing in the field. An effective geomechanical model, along with petrophysical interpretation has proved to be helpful in enhancing recovery, improving frac success rate and ultimately, reducing cost on operations. The approach emphasizes the importance of continuous update of the model to deal with variation within the field area and heterogeneity in volcanic rocks.
Choudhary, Manish (Shell Technology Center) | Nair, Saritha (Shell Technology Center) | Pal, Sabysachi (Shell Technology Center) | Munimandha, Amuktha (Shell Technology Center) | Kohli, Abhinandan (Shell Technology Center) | Nirmohi, Samiksha (Shell Technology Center) | Gupta, Shyam (Shell Technology Center) | Jain, Sid (Shell Technology Center)
Integrated analysis of data together with fit-for-purpose modelling can help in fast track maturation of opportunities. In 2012, an opportunity to increase oil by implementing waterflood was identified, and last year was further reviewed by Shell. An integrated approach helped the team to mature ten development wells within three months which were subsequently drilled and helped the operator to surpass their production targets.
The field located in Western Desert, Egypt comprises of an Upper Cretaceous tidal channel system across four key reservoirs where sand thickness ranges between 2-15 m. Large uncertainties in reservoir extent, architecture and properties required the integration of data across multiple disciplines for identifying new development wells.
It was recognized early on that the construction of full-field fine-scale static models would be time-consuming and hence a simplified fast-track approach was used for maturing the opportunity. Conceptual depositional models were built by integrating dipmeter data, image logs and core facies descriptions to understand the direction of continuity of tidal channels, tidal bars and mud flats.
Net sand thickness maps were then constructed to represent the conceptual depositional model and integrated with the production behaviour of the wells. Production from historical wells drilled up to 2012 caused non-uniform pressure depletion across reservoirs. The pressure data from Modular Dynamic Tester (MDT), along with the production-injection history, was reviewed to identity both areal and vertical stratigraphically connected areas which were incorporated in the net sand maps. The constructed maps were quality checked with pressure and production data so as to validate the range of in-place volumes. Net sand maps, porosity maps and saturation models were combined to generate Hydrocarbon Pore Volume (HCPV) maps used to identify new well opportunities.
Separate sector models were also constructed to evaluate the waterflood and to optimise the decision parameters like injector-producer spacing, injection rates, voidage replacement ratio and target reservoir pressure. A range of type curves were generated from Monte Carlo simulation runs for all key sub-surface uncertainties then was used to estimate the low, base and high case recoverable volumes for the identified well locations and patterns.
The identified wells were drilled between February and August 2015 and helped increase production rates of the field by over 5,000 stb/d.A fit-for-purpose modelling using sand maps and connectivity maps can often greatly help in fast-tracking opportunity maturation and fine-scale detailed simulation modelling may not provide additional value.
Sarma, Dilip Kumar (Oil and Natural Gas Corporation Ltd.) | Pal, Tej (Oil and Natural Gas Corporation Ltd.) | Kumar, Dileep (Oil and Natural Gas Corporation Ltd.) | Lahiri, Gopal (Oil and Natural Gas Corporation Ltd.) | Manchalwar, V V (Oil and Natural Gas Corporation Ltd.)
Mumbai Offshore fields are consisting of heterogeneous limestone reservoirs. Some of the reservoirs consist of tight carbonate with poor wellbore transmissibility. With the maturity of the fields, improving production from tight reservoirs has become the main focus for sustaining overall production. However, the responses of conventional stimulation techniques such as matrix acidization with self-diverting acid, deep penetrated acid, conventional acid fracturing etc. are not very encouraging in a tight reservoir, which calls for novel stimulation approach.
To address the issues, reservoir properties, well completion strategies and previous stimulation practices were analyzed in collaborative approach. Based on analysis, a different stimulation approach Closed Fracture Acidizing (CFA) was identified as the potential technique. Closed Fracture Acidizing reopens previously created fracture system with a pre pad fluid pumped at high rates. It involves creating fractures with a viscous fluid, letting it close followed by pumping a suitable acid system at matrix rate for etching the fractures. To improve treatment efficiency vis-à-vis better etched conductivity, different techniques such as leak-off control additives, effective diversion system, viscous acid systems etc. are applied.
For application of the technique, some low producing wells completed in Mukta pay of Heera field, A1 and L1 layers of Mumbai High field and Panvel pay of B-192 field were identified. The well specific treatments were designed by using Cross-linked Guar gel for creating fractures and a customized foamed acid system for etching of fracture faces. Foamed acid has been selected in these treatments for better exposure of acids in the entire fracture network and effective flow back of the treatment fluids. The foamed acid was customized by using a viscoelastic surfactant (VES) as foaming as well as viscosifying agent. Converting the acid system to stable foam greatly controlled fluid leak-off, increased the effective fluid volume and retarded the reaction rate, which is desirable in carbonate reservoirs. The various additives such as cross-linker, breaker etc. were optimized at onboard laboratory in the well stimulation vessel.
The jobs have been implemented in ten wells under constant monitoring of treatment parameters during fracturing, closure and acidization. Post CFA jobs indicate 670 bbl/day of oil production from a non-flowing well and significant improvement of productivity in other wells.
This paper describes the details of Closed Fracture Acidizing technique, treatment design, lessons learned during execution and results. The novelty of the approach over the conventional stimulation techniques in tight carbonate reservoirs are the treatment methodology and use of foamed acid system for better acid etched fracture conductivity.
Long-term wellbore integrity is an increasingly important factor that directly affects hydrocarbon production and optimized-wellbore economics. The industry shift toward drilling in harsher conditions, including high-pressure/high-temperature (HP/HT), deepwater, unconventionals, mature fields/high-temperature (HT) oil-recovery techniques, etc., as well as increasing regulatory scrutiny, has made operations even more challenging. Zonal isolation is typically achieved by placing annular sealants between the casing and formation. Sealants serve as annular barricades to help protect/support the casing while preventing unwanted fluid communication. Ideally, the sealant placement occurs in an optimum manner and initially presents a good bond-log result. However, zonal isolation can deteriorate over time, resulting in poor wellbore economics attributed to costly remedial treatments, potential environmental issues, and sometimes premature well abandonment.
As a result, oil companies have shifted focus toward preventing wellbore integrity failures using predictive modeling to optimally design sealants to withstand pressure and temperature cycles throughout the life of the well. These models require critical input data typically obtained by performing destructive and nondestructive tests to characterize the thermomechanical properties of sealants. Albeit multiple studies have been performed to characterize sealant properties, the vast majority do not result in the measurement of key properties under in-situ simulated downhole conditions. Testing equipment limitations require the samples to be transferred from curing chambers to loading cells, thereby exposing tested specimens to unrealistic curing and loading histories. Testing conditions are often different from those actually experienced downhole because of equipment constraints, resulting in inaccurate exemplification of the sealant’s performance in the wellbore. Consequently, the need for in-situ characterization of sealants under simulated downhole conditions becomes evident.
This study describes an innovative and novel methodology comprising an HP/HT in-situ triaxial testing apparatus for measurement of sealant mechanical properties (i.e., compressive strength, Young’s modulus, and tensile strength) under simulated downhole conditions. The equipment can be used to perform both curing and testing using the same apparatus, thus eliminating depressurization and cooling of test specimens. Additionally, at minimum, three samples can be tested sequentially for statistical analysis and uncertainty mitigation, along with performing real-time monitoring of total HP/HT shrinkage. The testing apparatus is rated to 30,000 psi for axial loading, 20,000 psi for confining loading, and 400°F. Preliminary validation of Young’s modulus was performed with five different plastic samples, yielding error percentages of less than 5% compared to measurements performed using a standardized loading frame. Compressive strength validation was performed using a 16-lbm/gal cement design, and error percentages of less than 2% were obtained compared to standardized testing procedures. Moreover, a 16-lbm/gal cement system was also used to help assess the functionality of the testing apparatus under simulated wellbore conditions with temperature and pressure ranging from 80 to 350°F and 3,000 to 8,000 psi, respectively.
Panna field is located in the western offshore region of India and produces oil and gas from Middle Eocene and Early Oligocene Bassein limestone. Production is taken mostly through 3 ½" or 4 ½" tubing through a packer set in 7″ liner. The Panna-Mukta-Tapti Joint Venture (PMT JV) took up a plan to revive wells addressing well integrity issues and limitations associated with old completion jewelry for increasing the production.
Work-over campaign was planned for four wells on PB and three wells on PC platform to enhance production. The plan was to cut and retrieve the old completion and tubing above the 7″ permanent packer and install improved completion, having facilities of Permanent Down Hole Gauges (PDHG), Gas Lift Mandrel (GLM) and Chemical Injection Mandrel (CIM) through an additional packer set in 9-5/8″ casing.
In line with two barrier philosophy, two plugs were set inside the production tubing, one at TRSSV (shallow-set) and another one below the production packer (deep-set). The plug below the production packer doubled-up to also hold back the workover fluid, which may have hampered the productivity of an already sub-hydrostatic reservoir, if losses occurred. However, at the end of workover operations, the retrieval of this deep set plug could not be done even after various attempts and spending valuable rig time. This problem was faced with three out of the first four wells, which proved to be a challenge and forced the team to devise a new strategy for remaining wells.
At this point, an ingenious solution was devised to employ Plasma Based Punctures (PBP) to puncture the tubing in the limited space between the packer and the deep set plug to kick back the wells into production. Rig based PBP operations were carried out on two PC wells and Rig less PBP operations were carried out on three PB wells to get them online post work over operation. This resulted in saving several hours of rig time as the deep set plugs could not be retrieved in the conventional planned slick line operations.
This paper intends to highlight the challenges faced, and how PBP proved to be the optimum solution, by simplifying operations and ensuring the timely delivery of production.
The PBP operations proved viable through savings on energy, resources, time and cost associated with work-over jobs. The potential savings were roughly 780,000 bbls of oil which were significant for the aging asset. It is therefore, a potent alternative to other costly solutions in a scenario that often fails to deliver objectives, as happened in this campaign.
Radhakrishnan, Venkataramanan (Schlumberger) | Bujnoch, John. (KrisEnergy Gulf of Thailand Ltd.) | Meteerawat, A. (KrisEnergy Gulf of Thailand Ltd.) | Wannaduriyapan, P. (KrisEnergy Gulf of Thailand Ltd.) | Abbasgholipour, Ali (Schlumberger) | Onkvisit, Sirikanya (Schlumberger)
The Wassana field is challenging in terms of formation. Past experiences with offset wells in the field confirmed that drilling below 5,000-ft (1524-m) true vertical depth (TVD) is challenging due to the formation becoming harder and more interbedded, resulting in premature failure of conventional polycrystalline diamond compact (PDC) bit designs. Several bit designs were tested, but most of the cutting structures were damaged when drilling below 5,000-ft (1524-m) TVD. The best strategy to optimize drilling performance in the Wassana field is to identify a suitable bit design with a durable cutting structure, which can drill beyond 5,000 ft (1524 m).
To meet the operator's goals, the service company proposed drilling the section with a new-technology bit that uses conical diamond elements (CDEs) on the bit blade with a rotary steerable system. The goals were to achieve the directional objectives in the shallow interval and successfully drill beyond the harder interval (8,000 ft TVD) down to TD. The rock strength of the formation ranges from 12,000 to 15,000 psi.
The PDC bit has CDEs with an ultrathick synthetic diamond layer, which provides extra durability for drilling at higher rate of penetration (ROP). This bit can withstand more weight on bit compared with conventional PDC bits of the same size, resulting in additional mechanical energy to penetrate the formation more efficiently. The CDEs protect the PDC bit by making it more stable, resulting in better tool face control. The 8½-in. directional section was successfully drilled to 11,200-ft 3414-m MD, which was the longest interval in the field. The strategically placed CDEs on the bit blades in conjunction with conventional PDC cutters not only increased the point loading but also enabled smoother torque control, leading to better steerability and durability. None of the offset wells achieved the feat of drilling more than 7,500 ft (2,286 m). The bit achieved the operator's goal of drilling 9,690ft [2954-m] and 10,043-ft [3061-m] MD. This result not only saved a trip but enabled the operator to gain confidence in redesigning the well profile with a greater measured depth. The operator accepted the fact that the bits with CDEs are more durable and also able to achieve the directional profiles better than conventional PDC bits. As a result, the operator changed the drilling strategy to drill longer intervals in the 8½-in. section. This strategy will increase drilling efficiency and lower the drilling risk of planning for more trips. The subsequent wells were planned using the same bit with CDEs to minimize the number of runs.
The Mangala field is located in the northern part of the onshore Barmer Basin in India. The Fatehgarh Formation is the primary reservoir, which was deposited during the rifting phase that created the Barmer Basin during the late Cretaceous to early Palaeocene period. The majority of reservoired oil is contained within the Upper FM1 member of the Fatehgarh Formation, composed of single storey and multi-storey stacked, meandering channel sands. These sands vary in thickness from 3 to 7 meters, with net-to-gross ranging from 18% to 78%. Well-based correlation of flood plain shales and fluvial sands in such a heterogeneous fluvial system poses a major challenge for reservoir characterization.
These thin fluvial channel sands are not resolved in the conventional seismic data, which makes it difficult to map the lateral continuity of these sand units. Sparse-layer Inversion was performed on the 3D stack PSTM data, which resulted in a dataset with improved detectability and resolution. Results were validated using well log and production data. Amplitudes of the high resolution seismic data provided information on sand continuity and connectivity. Consequently, Colored Inversion was performed on this data which provided improved understanding of the lateral distribution of the thin FM1 channel sands.