First Look-Ahead VSP Guided Salt Dome Island Exploration Well Drilling in the UAE

An exploration well offshore UAE, which was the first of it's kind, was planned to be drilled from an island and within salt dome. Well planning was based on a structural model that was estimated using coarse 2D surface seismic (with no line crossing planned well location) and gravity measurements. This model, therefore, had a large uncertainty as to the salt location and geometry. Concerns of potential drilling hazards associated with salt required utilizing the ability of borehole seismic to look-ahead of bit to image salt and direct the well such that it would be sufficiently far away from salt face. Pre-job survey planning was first made assuming salt face to the northwest (based on gravity data) of wellhead and that the well would remain outside the salt. To ensure the well remains close, but not too close, Vertical Seismic Profile (VSP) was planned to include Salt Proximity Survey. Just prior to spudding, a surface core indicated salt was, in fact, southeast of wellhead, thus changing the objectives of VSP from locating how far away the well was from salt, to how soon will it exit salt. After survey modeling for four possible scenarios, Look-ahead Zero-Offset and Offset VSPs were acquired using vibroseis at the island, at each of four casing points and rapidly processed to guide drilling next sections. In the 26" section, the well started drilling in salt and there was concern that there would be problems with casing design if the well did not exit salt before 4000 ft. A Zero-Offset and Offset VSP were shot for reflection imaging off the salt face. The survey indicated the salt face was approaching the well but at low rate (due to dip) to ensure an exit before 4000 ft. The well was deviated southeast and it exited the salt at 3620 ft. In the 17.5" section, a second run of Zero-Offset and Offset VSP were acquired indicating the salt face was still moving away from the well toward the northwest. In the 12.25" section, a third set of Zero-Offset and Offset VSP was shot. This survey confirmed the salt face was moving continually northwest and it was suggested the well deviate northwest to remain closer to salt. A large reverse fault was also clearly imaged and confirmed by drilling. In the 8.5" section, the well was drilled northwest at high angle as could be tolerated until it was TDed below target formation "A". The final set of Zero-Offset and Offset VSP results showed the salt was, at the level of formation "A", farther northwest than could be imaged by these VSP. There has been little to no experience of drilling salt dome islands in Abu Dhabi. This paper demonstrated how look-ahead VSP guided exploration well drilling in the salt dome island. Out-of-the-box survey design and rapid turnaround processing successfully aided in imaging location of the salt face and allowed casing points to be made without having to plug back and sidetrack. Once out of the salt, VSP allowed the well to be drilled closer to salt without re-entering it.

A Customized High Performance Water-Based Mud Solved the Challenge to Drill Reactive Shale Formation and Simplify the Logistic Challenge in an Exploration Well in Offshore East Kalimantan, Indonesia

Exploration drilling obviously requires a robust drilling fluid system to be a key factor in overcoming both the known and unexpected challenges of a structure that consists of reactive clay and lost circulation zones. Extra consideration has to be given to regulatory environmental requirements and complications resulting from regional politics. A High-Performance Water Based Mud (HPWBM) system was selected to address the aforementioned issues. The HPWBM was customized to respond to the subsurface conditions with the main requirement to provide maximum shale inhibition through a non-dispersed environment. Polyamine was utilized to stabilize all types of clay; an encapsulation polymer and a non-ionic polymer were included to prevent dispersion and to seal micro-fractures. A complete shale study was performed to determine the optimum concentration of the base fluid and each shale inhibitor. Then hydraulic behaviour of the mud was simulated with contractor proprietary software to understand the parameters for optimal hole cleaning as well as Equivalent Circulating Density (ECD) simulation. The HPWBM system successfully facilitated the execution of the exploration well and provided highly effective clay stabilization. No Non-Productive Time (NPT) was recorded as a result of reactive clay issues. The mud system also facilitated a good rate of penetration (ROP), formation stability, and lubricity. Waste cuttings transportation was not required. In addition, there is also no requirement for costly base oil including its associated transportation costs. The successful implementation of the HPWBM yielded an estimating saving of 25% compared to invert emulsion fluids, prior to considering costs associated with an expensive Liquid Mud Plant (LMP), environmental, and freight costs. Significant cost savings were achieved by eliminating the need for LMP rental, mobilization and demobilization. Another notable saving was realized from the reduced system maintenance of the HPWBM as less dilution was required compared to a regular Water Based Mud. Thinking outside of the box and embracing the departure from the default consideration of an invert system with a thorough risk assessment augmented value to wellbore construction. A smartly designed HPWBM system provided performance comparable to an invert emulsion system but with superior benefits with respect to environmental protection, simplified logistics and lower costs.

A Novel Approach to Drilling Through Challenging Formations With Complex Logging Bottomhole Assembly in an Exploration Well, North Sea

The southern part of the North Sea continental shelf is known for large intervals of hard, compact, cretaceous chalk formations that historically have proven to be challenging to drill through in one run. In recent years technology has been developed to drill specifically through these types of sedimentary successions as effectively as possible to be durable and competitive in similarly challenging drilling settings. Formations that previously would require multiple bit runs are now being drilled in one. The exploration well 2/9-6 S Eidsvoll, operated by MOL Norge AS, was drilled in this area of the North Sea continental shelf, with this specific type of chalk being drilled in the 12 ¼-in. section. Because the 12 ¼-in. section consisted of several different lithologies, it was vital to design the bottom hole assembly (BHA) to handle the diversity of rock formations to be drilled. Lithologies ranging from soft, swelling clay to hard compact chalk with an Unconfined Compressive Strength (UCS) as great as 20,000 psi were expected. In addition to managing the challenging drilling environment, determining the casing setting depth was of the highest priority because a pressure ramp was expected near the planned setting depth. This pressure ramp is located in the Base Cretaceous Unconformity (BCU), which is a well-known seismic reflector in the area. The top of this reflector had an uncertainty of ±75 m, which is not ideal following a decision to set the 9 ⅞-in. casing as near as possible to the reservoir. Seismic-while-drilling technology was applied to reduce this uncertainty and better tie-in the acoustic velocities to the pre-drilling seismic model. In addition, a geomechanics team was tasked with creating and updating the prognosed pore pressure estimation model. This information was important in making the mud-weight decision when drilling the 8 ½-in. section.

Geophysical Aspects of Reservoir Characterization of Tight Gas Play in the Dnieper-Donets Basin

The objective of this work is to describe a comprehensive approach integrating seismic data processing and sets of wireline logs for reservoir characterization of one of the tight gas plays of the Dnieper-Donets basin. This paper intends to discuss a case study from seismic data processing, integrating seismic attributes with formation properties from logs in a geocellular model for sweet spot selection and risk analysis. The workflow during the project included the following steps.Seismic data 3D processing, including 5D interpolation and PSTM migration.Interpretation of limited log data from 4 exploration and appraisal wells.Seismic interpretation and inversion.Building a static model of the field.Recommendations for drilling locations.Evaluation of the drilled well to verify input parameters of the initial model. The static model integrated all available subsurface data and used inverted seismic attributes calibrated to the available logs to constrain the property modelling. Then various deterministic and stochastic approaches were used for facies modeling and estimation of gas-in-place volume. Integrating all the available data provides insights for better understating the reservoir distribution and provided recommendations for drilling locations. Based on the combination of the geocellular model, seismic attributes and seismic inversion results, the operator drilled an exploration well. The modern set of petrophysical logs acquired in the recently drilled well enforced prior knowledge and delivered a robust picture of the tight gas reservoir. The results from the drilled well matched predicted formation properties very closely, which added confidence in the technical approach applied in this study and similar studies that followed later. It is the fork in the road moment for the Dnieper-Donetsk basin with huge tight gas potential in the region that inspires for exploration of other prospects and plays. A synergy of analytical methods with a combination of seismic processing, geomodeling, and reservoir characterization approaches allowed accurate selection of the drilling targets with minimum risk of "dry hole" that has been vindicated by successful drilling outcome in a new exploration well.

Construction of a Multipurpose Exploration Well in the Jurassic Deposits Subsequent Transfer to Production Enabled by Metal Expandable Barrier Installed Behind the Casing

Summary The resource base of the north of the West Siberian oil and gas province is the basis of Russia's energy strategy. Among the northern territories of the province, the Nadym-Purskaya, Pur-Tazovskaya and Yamal oil and gas regions (OGRs) are the leaders in terms of estimated gas reserves (Figure 1). However, the largest deposits of the first two OGRs are in the stage of falling production. Therefore, the main prospects should be associated with the Yamal OGR, which has not yet been put into active operation. It is logical that along with the development of traditional methods of extraction of "dry" natural gas, the government of the Russian Federation has approved a plan for the production of liquefied natural gas based on the fields of the Yamal Peninsula, which is currently being actively implemented by PJSC "NOVATEK". (https://www.novatek.rU/m/business/exploration/)

Successful Application of a New Generation of Clay Inhibitor Polymers While Drilling a Deep Exploration Well in the Astrakhan Region

This paper presents the results of laboratory studies and field application of a drilling fluid based on a new generation of polymer inhibitors. The summarized results of the application confirm the effectiveness of the new polymer type used. The body of the article is devoted to the experience of using an innovative drilling fluid system for drilling an exploration well in the Astrakhan gas condensate field. One of the features of the Astrakhan gas condensate field is a number of intervals of possible complications: lost circulation zones, prone to clay swelling and caving, and presence of salts and hydrogen sulfide in the reservoir. One of the solutions for ensuring trouble-free drilling in such conditions is using an oil-based drilling fluid (OBM). However, OBM is often avoided when drilling exploratory wells due to environmental and technological limitations. In this connection, the project team carried out work on selection and development of a water-based drilling fluid formulation, which would ensure the most trouble-free and cost-effective drilling operations. Considering these studies, a drilling fluid was selected based on a new generation of inhibitor polymers. The key feature of the proposed formulation is the use of a new polar inhibitor polymer. The selected formulation showed the best laboratory test results after which it was approved for application. The main risk of using the new drilling fluid formulation was lack of filed experience in using this system in similar geological conditions. At the same time, laboratory tests showed that the proposed alternative mud formulations did not provide the required level of contamination resistance and inhibiting ability. Over the period from April to September of 2020, the exploration well was successfully drilled at the Astrakhan gas condensate field using the selected drilling fluid based on a new polymer type. Using the same drilling fluid type, four intervals - from the surface pipe to the production liner, - were drilled.

The application of VOI method to shape a strategy of additional exploration

Background. An optimal exploration strategy creates a significant share in value of project on exploration stage. The paper describes an example of solving the following tasks: determining the feasibility of additional exploration drilling; evaluating the value of drilling of one or more exploration wells; determining the optimal placement for exploration wells and drilling order. Authors presenting the modification of VoI (Value of Information) method and its application. Materials and methods. Complex probabilistic models were created summarizing main uncertainties and limitations, both geological, technical and technological. At the first stage three equiprobable geological concepts were made. For each concept probabilistic geological modelling was proceeded and then realizations corresponding to values of reserves P10, P50, and P90 were selected. Further, detailed production forecasts and economic estimates were performed. The analysis used the well pad and the corresponding area for exploration drilling as a unit of calculation. In the article the authors introduced the concept of remaining uncertainty. Application of modified VoI method allowed to form ‘dynamic’ (i.e. depending on exploration wells drilling order) range of areas for additional exploration which provide the best decrease of remaining uncertainty. An additional exploration strategy has been formed, which includes the necessary and sufficient number of wells and their drilling order. A decision tree was created depending on the success or failure of each subsequent exploration well. Results. The use of the modified VoI approach made it possible to achieve the objectives and obtain economical estimates, all of which combined to facilitate the adoption of decisions. As a result, a program for two exploration well drilling was created which would reduce the uncertainty by 90% from its initial value. Conclusions: The adopted VoI method could be applied to fields at the stage of additional exploration as well as to fields at early exploration stage to develop an exploration drilling strategy.

Expanding the Capabilities of Modern Wireline Formation Testers for Understanding the Structure of Tight and Fractured Suprasalt Carbonate Field in West Kazakhstan

Low porosity carbonate reservoirs of the Carboniferous and Devonian periods of the Caspian Basin in Western Kazakhstan are challenging to characterize using traditional well logging methods due to the complex structure of the pore space, which necessitates lengthy and sometimes ineffective production well tests. Limitations of standard well logging methods make it impossible to reliably identify productive reservoirs, determine boundary conditions, and delineate saturation. As a result, a unique approach is required, which includes the integration of special "high-tech" logging tools and wireline formation testers (WFT). This paper effectively demonstrates the use of this approach in an appraisal exploration well. The use of a wireline formation tester in conjunction with modern complex fluid analyzers and a radial probe allowed for testing several carbonate intervals with extremely low-permeability in one trip, which previously required stimulation to trigger fluid inflow in a cased well. This provided a new perspective on understanding the reservoir structure in the shortest amount of time possible.

Exploration and Formation Testing of Low Permeability Clastic Reservoir in Hot Slim-Diameter Open-Hole Well

The objective of the logging campaign was to explore the hydrocarbon deposits in low-permeability clastic reservoirs utilizing an advanced logging suite and a high-tech wireline formation tester (WFT). The exploration well, which had a diameter of 146 mm and was drilled to a vertical depth of 4750 m, had a temperature of 147 degrees Celsius downhole. Despite the challenging geological and downhole conditions: low permeability reservoir, high reservoir temperature, small wellbore diameter, and very high salinity drilling mud, the advanced logging suite data, which included nuclear magnetic resonance (NMR) and cross-dipole broadband acoustic logging, was successfully acquired. The WFT, which consists of a unique radial probe technology for efficient sampling of extremely low-permeability formations and a downhole fluid analyzer to determine the nature of the inflow and make rapid operational decisions in real time, was then used to perform downhole fluid analysis and sampling stations. Oil and gas-saturated reservoir intervals were identified, their porosity, water saturation, and permeability were evaluated, and an optimal open hole WFT program was produced as a result of the extended logging suite's interpretation. Special technological operations were performed during well logging in this well, allowing for the acquisition of high-quality NMR data under extreme conditions. Rapid processing and interpretation of well logging data, performed without any a priori reservoir data, allowing for the identification of the best permeability intervals in oil and gas-saturated reservoirs and the design of an optimal WFT program in an open hole. Downhole fluid analysis and sampling stations were performed with WFT with pressure build-up to determine fluid mobility to validate the presence of productive intervals. Thus, in several downhole trips in a relatively short period of time, potential hydrocarbon layers were assessed in an open hole section, and in the presence of sufficient fluid mobility, the saturation of the interval was determined by WFT. It is important to note that downhole gas samples were acquired in intervals having fluid mobility less than 0.06 mD/cP, where the conventional well test would most probably fail to induce a flow without stimulation. An integrated approach using modern well logging methods made it possible to solve the set geological challenges in the extreme conditions in this exploration well, where traditional methods would introduce significant uncertainties.

Successful Wellbore Pressure Management Using Intelligent MPD and Continuous Circulation System on an HPHT Well in Vietnam

A managed pressure drilling (MPD) and early influx detection system is gaining worldwide acceptance as an enabling technology for drilling wells with challenges that can lead to tremendous nonproductive time (NPT), significant unplanned costs, and increased risk exposure. MPD counteracts the high cost of these wells by delivering significant savings when eliminating fluid losses or well control events that cause NPT. MPD technology has proven that is used to not only reduce NPT but also enable access to reserves previously considered un-drillable. In this case history, MPD helped to reach reserves that could not be reached in the first well. Client planned to drill the well A, which is its second offshore exploration well. Early on in 2019, the campaign encountered significant problems because of high temperatures and a narrow pore-pressure/fracture-pressure (PP/FP) gradient window. Additionally, using conventional drilling methods in offset wells led to problems relating to kicks, loss scenarios, and stuck pipe. Before drilling the second exploration well, the relevant parties considered that the first well-presented multiple drilling issues, and they drew from past success. The latter job had ended with reaching all the well targets despite high-pressure/high-temperature (HP/HT) conditions using a continuous circulating device in conjunction with an MPD system. Therefore, this combination of technologies was chosen to drill the well A. The operator used the MPD system, from the start when drilling the 14 3/4-in × 16-in. hole section to the end when drilling the 8 1/2-in. hole section, in offshore Vietnam. Applying MPD technology on this well resulted in many benefits, including the main benefit of always controlling the bottomhole pressure through the challenging zones. MPD also helped to maintain the equivalent circulating destiny (ECD) and equivalent static density (ESD) during drilling, connections, and a logging operation to mitigate the risk of any gas breaking out at the surface and to drill the well to the desired target depth. This paper focuses on using MPD technology in conjunction with the continuous circulation system, in offshore Vietnam. It goes into detail by describing the experience and providing some of the lessons learned.