Offshore Wells Research Articles

Modeling Pore Pressure, Fracture Pressure and Collapse Pressure Gradients in Offshore Panna, Western India: Implications for Drilling and Wellbore Stability

Pore pressure modeling has proven and direct implications in oil and gas exploration and development. Abnormal pore pressure leads to drilling complexity and well control issues because of reduced mud window, contributing to major non-productive times and steep drilling cost. A comprehensive pore pressure–fracture pressure model plays a critical role in successful well drilling. This work caters to the pressure modeling of Panna area in Mumbai offshore basin, western India. Two offshore wells, drilled through 4 km of Tertiary sedimentary succession down to Cretaceous basaltic basement, were analyzed to interpret the vertical stress, pore pressure, fracture gradient and collapse pressure. Vertical stress profile was generated from density logs; pore pressure was estimated using Eaton’s method by employing resistivity and sonic logs. Calculated pore pressure was calibrated with various direct downhole measurements and various well events. Compaction disequilibrium was inferred as key mechanism for generating mild overpressure in Oligocene to early Miocene shales (14–15 MPa/km), while it increases sharply against early Eocene sediments, and hard overpressure with near-lithostatic gradient (22 MPa/km) was detected in the underlying Paleocene shales. The mid-Eocene Bassein formation, the primary hydrocarbon reservoir, reveals sub-hydrostatic condition (7.5 MPa/km) resulting from production-related depletion. Estimated fracture pressure was calibrated with available leak-off test data. Mohr–Coulomb rock failure criterion was employed to estimate collapse pressure and validated with the observations from caliper log to address the wellbore stability issues. This study provides insights on downhole pressure behavior across stratigraphy, to achieve optimum drilling mud designing as well as safe and successful operational planning.

Major CO2 blowouts from offshore wells are strongly attenuated in water deeper than 50 m

AbstractGrowing interest in offshore geologic carbon sequestration (GCS) motivates evaluation of the consequences of subsea CO2 well blowouts. We have simulated a hypothetical major CO2 well blowout in shallow water of the Texas Gulf Coast. We use a coupled reservoir‐well model (T2Well) to simulate the subsea blowout flow rate for input to an integral model (TAMOC) for modeling CO2 transport in the water column. Bubble sizes are estimated for the blowout scenario for input to TAMOC. Results suggest that a major CO2 blowout in ≥50 m of water will be almost entirely attenuated by the water column due to CO2 dissolution into seawater during upward rise. In contrast, the same blowout in 10 m of water will hardly be attenuated at all. Results also show that the size of the orifice of the leak strongly controls the CO2 blowout rate. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

Analytical and Experimental Investigation of the Critical Length in Casing–Liner Overlap

Offshore drilling operations exhibit various difficulties attributed to shallow flows worldwide. One of the most common practices for drilling offshore wells is to use liners and liner hangers rather than using full casing strings. This reduces the cost of drilling operation. Liners and liner hangers are required to pass certain standards prior to their deployment in the field. This ensures their ability to withstand harsh downhole conditions and maintain the integrity of the well. A liner hanger contains an integrated seal assembly that acts as a barrier to prevent fluid migration. The cement that is placed within the casing–liner overlap is also considered a barrier, and it is critical that it maintains the integrity of the well by mitigating fluid migration to other formations and to the surface. The failure of this dual barrier (cement and seal assembly) system to seal the annular space can result in serious problems that might jeopardize a well’s integrity. Typically, in field applications, the length of a casing–liner overlap is chosen arbitrarily. In some cases, shorter overlaps (50 to 200 ft) are chosen because of the lower cost and easy identification of leaks during pressure tests. However, some loss of well control incidents (particularly the incident that motivated this study) have been linked to fluid leakages along the casing–liner overlap. This paper investigates the critical length of the casing–liner overlap by modeling gas leakage through the cement placed within the overlap using analytical and experimental approaches. Leakage scenarios were developed to mimic gas migration within the cement in the casing–liner overlap. The results showed that the longer the casing–liner overlap, the higher the leakage time. The results also showed that the current casing pressure test duration of 30 min may not be adequate to verify the integrity of the cement within the overlap. Based on the results and analyses, it is recommended to increase the pressure test duration to 90 min. In addition, the results suggest that the length of the casing–liner overlap should not be less than 300 ft to maintain the integrity of the well in the case of gas influx. Further details are highlighted in the results section. In practice, the current rationale behind the selection of a casing–liner overlap length is not sustainable. Thus, the major advantage of this study is that with field data, it provides both scientific and research-based evidence that can be used to inform the decision behind the selection of the casing–liner overlap length, especially in gas migration-prone zones.

Value of ROV Data Extends to Decommissioning Strategy

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 28312, “Understanding the Global Scientific Value of Industry ROV Data To Quantify Marine Ecology and Guide Offshore Decommissioning Strategies,” by D.L. McLean, University of Western Australia; P. Macreadie, Deakin University; D.J. White, University of Southampton and University of Western Australia; P.G. Thomson, University of Western Australia; A. Fowler, New South Wales Department of Primary Industries; A.R. Gates, National Oceanography Centre, UK; M. Benfield, Louisiana State University; T. Horton, National Oceanography Centre; D. Skropeta, University of Wollongong; T. Bond, University of Western Australia; D.J. Booth, University of Technology, Australia; E. Techera, C. Pattiaratchi, and S.P. Collin, University of Western Australia; D.O.B. Jones, National Oceanography Centre; L. Smith, Woodside Energy; and J.C. Partridge, University of Western Australia, prepared for the 2018 Offshore Technology Conference Asia, 20–23 March, Kuala Lumpur. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. Remotely operated vehicles (ROVs) are used by the offshore oil and gas industry to monitor the integrity of subsea infrastructure and, in doing so, collect terabytes of video and in-situ physical data from inaccessible regions and poorly understood marine environments. The complete paper describes the potential global scientific value of video and other data collected•by ROVs. ROVs and the Offshore Oil and Gas Industry Nearly one-third of global production of oil and gas is sourced offshore. Tens of thousands of offshore wells have been drilled, and more than 900 large-scale offshore oil and gas platforms have been installed. The offshore industry relies on underwater observation, control, and intervention, tasks performed increasingly by ROVs; over 700 were in operation globally at the time the paper was written. The advancement of ROV technology for the industry was prompted in the 1970s by developments extending into water depths beyond the capabilities of divers, and by the desire to reduce reliance on diving operations. Modern ROVs fall into two main classes: work class and observation class. A work-class ROV is car-sized, usually cuboidal, with a buoyant upper part containing power equipment, thrusters, manipulators, and cameras. An umbilical connection to the surface vessel provides electrical and fiber-optic connections that allow control and data transfer. Observation-class ROVs are smaller—sometimes briefcase-sized—with limited power and manipulation capabilities, and are used primarily for inspection purposes. For observation missions that can be conducted without real-time intervention, autonomous underwater vehicles (AUVs) are increasingly popular. These are generally torpedo-shaped, with higher hydrodynamic stability than ROVs, and can offer a similar image-gathering platform. Oil and gas projects and other ocean-based industries such as offshore wind use ROVs at multiple stages in a project’s life. Surveys of the region before installation or construction are conducted using ROVs or AUVs to identify the bathymetry and substrate conditions for hazard assessments and to provide parameters for engineering design. Drilling activities commonly involve ROV monitoring at the seabed level, and, when the production facilities are installed, ROVs are used to perform observation of all subsea activities. During operation of a project, ROVs are used for inspection and intervention. The manipulators operate valves and interchange components, and, if required, can undertake cutting. Inspections include visual surveys as well as checking of anode electropotentials and clearance of marine fouling. Inspections commonly are undertaken annually but can be more or less frequent depending on risk level and maintenance requirements. In total, the ocean around a typical oil and gas development may be visited dozens of times by ROVs during the project’s life.

Evaluation of Bismuth-Tin Alloy for Well Plug and Abandonment

SummaryAs an alternative to cement, bismuth-tin alloy (BiSn) containing 58-wt% bismuth (Bi) and 42-wt% tin (Sn) has been proposed for plug and abandonment of offshore wells. Alloy seals are advantageous over cement because they can be significantly shorter, reducing well-abandonment cost. Besides being able to deliver alloy pellets and melt them in situ, adhesion with common lithologies found in hydrocarbon reservoirs is also necessary. In addition, within the likely extremes of stress variability, the bond should be sufficiently strong to withstand the differential pressure across the plug. In this paper, we present a series of tests conducted in our laboratory for evaluating the alloy/rock bond. To overcome the intrinsic lack of chemical affinity and the resulting nonwetting nature of the alloy, we propose capillary intrusion into the porous-network of the rock. Above the capillary entry pressure, penetration distance by intrusion is controlled by available alloy volume. As a function of intrusion, we measure the quality of the bond through shear and tensile tests. Results for rocks, cement, and cement/limestone cores are also reported for comparison. Isolation quality is evaluated through permeability tests, performed both parallel and perpendicular to the macroscopic bond interface. For shale, we propose a surface treatment before plug placement that also prevents plug displacement under differential pressures. Strength is best achieved by straddling permeable media and shale. For deployments within tubing or casing, similar bond-strength evaluations can be conducted.

Software System Enables Effective Flow-Assurance Management

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191951, “A Smart Software System for Flow-Assurance Management,” by Akanksha Jain, SPE, Nilay Patel, SPE, Paul Hammonds, and Shirish Pandey, Cairn Oil and Gas, prepared for the 2018 SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 23–25 October. The paper has not been peer reviewed. Access to real-time production and injection data is of great benefit to the production optimization engineer. This paper describes a smart management system used for retrieving and evaluating all flow-assurance-related data for more than 700 of the operator’s onshore and offshore wells. The paper discusses system architecture, interface details, design, functionality, visualization, application, and benefits. Introduction Cairn Oil and Gas is the operator of three major blocks currently producing in India: Block RJ-ON-90/1 (Rajas-than), CB/OS-2 (Cambay Basin), and PKGM-1 (Ravva) constituting more than 700 wells, operated on behalf of its joint venture partners. These wells are either self-flowing or use a variety of•• artificial-lift systems. Waterflooding provides pressure maintenance in most fields. Injectivity of water injectors is, therefore, critical in maintaining levels of water injection required to achieve the stipulated recovery factor. Formation fluids have physical and chemical properties that have posed several flow-assurance challenges over time with regard to outflow performance and processing in surface facilities. These flow-assurance issues include inorganic scaling, organic scaling, corrosion, sand production, injectivity decline, and injector conformance, all of which can affect productivity and injectivity of the fields and thus lead to relatively inefficient waterflood. The Challenge Various software products are currently in use for management of operations requiring production- and injection-enhancement treatments in different fields. To ensure that wells are operating optimally, an integrated approach combining robust monitoring and data analysis of parameters affecting well performance is ideal. This was previously achieved through the cumbersome process of data retrieval from different sources, which was then compiled in different Excel spreadsheets. This time-consuming process delayed analysis and permitted errors in data input. As the importance of improving the quality of data management and analysis became clear, the need arose for automation of flow-assurance management across all assets. The platform described in this paper was intended to help design, evaluate, and monitor all chemical-intervention jobs, and monitor corrosion levels and scale-inhibitor squeeze performance by incorporating data from various sources within the production system. The analysis of the data enabled by this fully automated Web-based software helps in the execution of cost-effective treatments and well-production optimization. The same software system is also being used for well-integrity management for•all assets.

Settling of weighting agents in non-Newtonian fluids to off-shore drilling wells: Modeling, parameter estimation and analysis of constitutive equations

High-density solids such as barite and hematite are generally added to drilling fluids to increase their density, allowing the control of subsurface pressures. However, a variety of problems in drilling wells has been related to the gravitational settling of particulate materials. In this work, the dynamic behavior of barite settling in a synthetic paraffin-based drilling fluid was evaluated experimentally by monitoring the solid concentration as a function of time and height. The tests were conducted in a gravitational settling bench-scale rig using a gamma-ray attenuation technique. Following the standard approach of continuum mechanics, a mathematical model was developed to yield a single set of partial differential equations capable of describing all settling zones inherent in a batch sedimentation process. Further, by means of the predicted solid concentration profiles, it was possible to obtain the height of bottom piled up solids. The mathematical model takes particles compressibility under their own weight and permeability of the sediment into consideration. The parameters of the proposed constitutive equations for the effective pressure on solids and porous matrix permeability were estimated and statistically analyzed from the experimental profiles of solid concentration. In particular, the results obtained in this work indicated a good agreement between the model predictions and the experimental data.

Hierarchical Bayesian model for failure analysis of offshore wells during decommissioning and abandonment processes

Risk analysis of offshore wells decommissioning, and abandonment processes is challenging due to limited life-cycle information of the well, and failure data of safety barriers in place. To this end, it is essential to capture and implement the variability associated with the sparse data for conducting risk analysis with considerable confidence level. The hierarchical Bayesian analysis provides a viable alternative to address the uncertainty of the data through aggregation for each causation. Bayesian network, through its robust computation engine, is used to define dependence of causations and uses Bayes’ theorem to update the analysis as new information becomes available. In addition, the Bayesian network helps to represent complex dependencies among causations through appropriate relaxation strategy to minimize uncertainty in the data, link parameter of interest, and overall accident scenario modelling. This paper presents the integration of Hierarchical Bayesian model with a Bayesian network to conduct the risk analysis of well decommissioning and abandonment processes. The proposed methodology is illustrated using a well plugging and abandonment operational failure reported by the Department of Mineral Management Service (MMS). The results demonstrate the potential of the proposed approach as a robust means to study complex well decommissioning activities.

Changing of the guards: Detrital zircon provenance tracking sedimentological reorganization of a post‐Gondwanan rift margin

AbstractUnderstanding the development of sedimentary systems during continental rifting is important for tracking environmental change and lithospheric processes. Conceptual models have been developed for the sourcing, routing and facies architecture of sediments in rift‐settings, driven in part by quantitative sediment tracking. Here, we present laser ablation split‐stream detrital zircon U/Pb geochronology and Hf‐isotopes for post‐rift (Cretaceous‐Paleogene) clastic sediments from Ocean Drilling Program (ODP) wells and Plio‐Pleistocene palaeoshoreline material, from the southern margin of Australia. Provenance results are contextualized through comparison with well‐characterized source regions and regional pre‐ and syn‐rift sediment reservoirs to track changes associated with Australia‐Antarctica separation during East Gondwana break‐up. The provenance character of the post‐rift sediments studied are distinct from pre‐existing sediment reservoirs and demonstrate termination of previously stable sediment routing systems and a dominance of local basement of the Proterozoic Madura and Coompana provinces (~1.2 Ga and CHUR‐like Hf‐signatures; Moodini Supersuite) in offshore ODP wells. A composite post‐rift Cretaceous?‐Eocene sample in the easternmost well expresses characteristic Phanerozoic zircon age signatures associated with source regions in eastern Australia that are interpreted to reflect inversion in the Ceduna Sub‐basin to the east. Detrital zircon signatures in Plio‐Pleistocene palaeoshoreline sediment are also relatively distinct, indicating derivation from coastal erosion in the Leeuwin Complex (~0.5 and 0.7 Ga subchondritic grains) and Albany–Fraser Orogen (~1.2 Ga subchondritic grains) several hundred, to over a thousand kilometers to the west. Collectively, results highlight the fundamental geological processes associated with rifting that dramatically change the character of sediment provenance via (a) isolation of pre‐existing primary and secondary sources of detritus, (b) development of new source regions in basin compartmentalized highs and localized fault scarps, and (c) establishment of marine and coastal currents that redefine clastic sediment transport.

Early Oligocene marine canyon-channel systems: Implications for regional paleogeography in the Canterbury Basin, New Zealand

The Oligocene is a time of maximum submersion of the Zealandia landmass; it coincides with changes in oceanographic currents as well as with the inception of the Cenozoic plate boundary through New Zealand. Our analysis of offshore wells and seismic reflection lines in the Canterbury Basin reveals condensed Oligocene strata (<150 m thick), which were eroded by mid-Oligocene (~32–29 Ma) channels 1–10 km wide, 15–90 km long and up to ~200 milliseconds two-way-time deep. Onshore, we mapped corridors of complete erosion of the early Oligocene Amuri Limestone, overlain by younger Oligocene and Miocene strata using measured sections from the published literature. The synchronicity, similar trends, and comparable morphology of onshore and offshore channels suggest that they may have formed part of the same erosive system. We propose that a sea-level fall at ~32 Ma initiated the development of this drainage system with erosive channels converging towards canyons in the deeper water offshore. The drainage was active for up to 17 Ma, flowing primarily towards the south-east into the present-day Bounty Trough. The temporal (millions of years) and the spatial (hundreds of metres) scales of the sea-level fall are larger than would be expected for eustatic processes and we suggest that regional tectonic uplift played an important role in channel formation. The channel orientations and their eastward gradients, together with the Oligocene sedimentary facies observed in outcrop, suggest that the axis of uplift (and maximum topography) was primarily west of the Canterbury Basin. Tectonic shortening that collectively affected the western North Island – Marlborough Sounds – western Canterbury – western Otago regions may have produced uplift and eastward flowing early Oligocene channels in the Canterbury Basin. We observe that the orientations, geometries, and locations of early Oligocene drainage are similar to present day systems, suggesting they persisted as physiographic entities for at least 30 Myr, throughout Late Cenozoic plate tectonic deformation.

Proposal and Experimental Trials on an Autonomous Robot for Rigless Well Intervention

Summary Well interventions, especially in offshore wells, are costly and usually very time-consuming to conduct. This is related mainly to the need for a rig or a similar unit to perform these operations. In this paper we propose the development of an autonomous robot for rigless well interventions. The robot will be inserted through the tree using a special tool. This proposal will result in significant cost reduction by eliminating the rig when performing light–workover operations in offshore locations. This reduces intervention time because a simpler unit might be used to deploy the robot. Examples of operations that could be performed by the robot are production logging, gas–lift valve replacement, sliding–sleeve opening and closing, and plug insertion or removal. To evaluate this proposal, a conceptual robot was designed. The feasibility of this conceptual robot was evaluated theoretically. After that, a simplified test robot was constructed to test critical aspects experimentally, in laboratories, and in a test well. The traction system, energy storage, and a positioning algorithm were evaluated. In this paper we will outline the intervention strategy proposed, perform a theoretical evaluation of this proposal on the basis of the conceptual robot, and present experimental results obtained with the simplified test robot.

Guest Editorial: The Future of Subsea Well Access and Completions

Guest editorial A review of technologies currently applied in offshore environments to drill and complete subsea wells for hydrocarbon production confirms that many opportunities exist to improve methodologies in ways that can be more economically beneficial and more environmentally sustainable. Most drilling and completion challenges have been met and overcome on a case-by-case basis although collective knowledge, and industry improvements, have progressed rapidly since the late 2000s. Subsea completions for gathering hydrocarbons from subsea wells have demonstrated both environmental and economic benefits for offshore oil and gas projects. Barriers and opportunities for expanded use of subsea completions involve both technological and regulatory issues. Advanced technologies are needed to ensure long-lived and serviceable subsea•equipment. Reasonable regulations also are needed to make sure that the best available technologies and practices are considered in•rulemaking that affects subsea operations and future of subsea well access. Well Completions and Subsea Completions Completion is used in offshore oil and gas activities in two different contexts. A well completion involves a set of actions taken to convert an individual borehole into an operational system for controlled recovery of underground hydrocarbon resources. A subsea completion refers to a system of pipes, connections, and valves that reside on the sea floor and serve to gather hydrocarbons produced from individually completed wells and direct those hydrocarbons to a storage and offloading facility that might be either offshore or onshore. Subsea completions typically contain an upper completion, a lower completion, and a production tree. Advances in upper and lower completions followed normal developments in materials, pressure, and temperature ratings. However, significant advancements in subsea well access has occurred in the past few years. The later advancement reduced operational costs and led to the capability to develop one-trip, single-system, umbilical-less installation of tubing hangers. One of the remarkable accomplishments of the upstream offshore petroleum industry has been the development of technology that allows simplified but efficient subsea well access to carry out the operations in a more complex situation. Despite an increase in complexity, improvements in subsea well access and completion technology have allowed more complex well patterns to be drilled to a greater depth such that additional hydrocarbon resources can be developed at a greater distance from the drilling or production structure, allowing more energy to be produced with less environmental impact. In the past 15 years, mechanical subsea systems have been developed, which allow deepwater riserless drilling with weighted mud and with fluid returns to the drilling rig. Those systems allow a dual-gradient hydrostatic pressure to be applied, thereby more closely matching the natural deepwater pressure profile. While those systems have been used on a number of offshore wells, there is limited supply of the necessary equipment and other well-control issues must be carefully considered for each particular operation.

Choice of optimal technological operation mode of off-shore gas-condensate wells exploited in complicated conditions

The object of research is a new method for the approach to control the optimal technological regime of gas and gas condensate wells. It is noted that in order to optimize the technological regime of the well, by extracting liquid and solid particles, it is necessary to know the minimum value of gas production or gas flow rate, which, in turn, is provided by determining the corresponding value of the bottomhole pressure. To determine the bottomhole pressure at which the well reaches the optimal operating mode, an equation is obtained that has a complex structure with respect to the bottomhole pressure (pressure in the elevator shoe), for the solution of which the graphoanalytical method was used. The proposed method for optimizing the operation of gas and gas condensate wells was tested on the basis of actual data. And it is shown that it is possible to determine the optimal operating mode of gas and gas condensate wells by determining bottomhole pressure values at which liquid and solid particles are transported from the bottom of the wells to the earth's surface. In this case, the initial data for wells (No. 652 and 704) operated on the VII horizon of the Sangachal-Sea-Duvanny-Sea-Khara-Zira (Azerbaijan) field is used to determine their technological regimes. It is shown that it seems possible to increase the productivity of offshore gas and gas condensate wells by changing the design of their lifts and the proposed method allows to extract liquid and solid particles from the trunk to the earth's surface. For each case, the particle deposition rates in the gas medium and the gas flow rate in the elevator shoe were calculated. Judging by the value of the difference in the determined particle deposition rates and gas flow in the elevator shoe, the possibility of the formation of liquid plugs in the well is established. If a situation arises when the gas flow rate does not ensure the extraction of liquid particles on the earth's surface, it is proposed to change the diameters of the lifting pipes.

Combined geophysical and analytical methods to estimate offshore freshwater extent

Offshore fresh groundwater is increasingly suggested as a potential water resource for onshore human demands. In many cases, onshore pumping already draws significant fresh groundwater from offshore. However, offshore aquifers and the extent of offshore freshwater are usually poorly characterised due to data scarcity. This study combines geophysical data, hydraulic information and a first-order mathematical analysis to investigate offshore freshwater extent in the Gambier Embayment (Australia). A large seismic data set, combined with onshore and offshore bore-log geological profiles, are used to explore the regional offshore hydro-stratigraphy. Aquifer hydraulic parameters and onshore heads are obtained from onshore investigations. A novel application of Archie’s law, geophysical data and onshore hydrochemical data provide useful insights into the salinity profiles within four offshore wells. These are compared to steady-state, sharp-interface estimates of the freshwater extent obtained from a recently developed analytical solution, albeit using simplified conceptual models. Salinities derived from resistivity measurements indicate that in the south of the study area, pore water with total dissolved solids (TDS) of 2.2 g L−1 is found up to 13.2 km offshore. Offshore pore-water salinities are more saline in the northern areas, most likely due to thinning of the offshore confining unit. The analytical solution produced freshwater-saltwater interface locations that were approximately consistent with the freshwater-saltwater stratification in two of the offshore wells, although analytical uncertainty is high. This investigation provides a leading example of offshore freshwater evaluation applying multiple techniques, demonstrating both the benefit and uncertainty of geophysical interpretation and analytical solutions of freshwater extent.

A comprehensive review of the application of nano-silica in oil well cementing

Abstract Oil and Gas Industry is a Multi-Billion Dollar Industry. Drilling a well is costly, right from exploration to drilling and production to Enhanced Oil Recovery (EOR). Nanotechnology has the potential to introduce revolutionary changes in several areas of the oil and gas industry, such as exploration, drilling, cementation, production, EOR, etc. Use of Nanotechnology in the cement slurry can also achieve solutions to some of the problems pertaining to oil well cementation. Nano-silica is a better alternative compared to conventional additives like calcium chloride and silica, because as compared to calcium chloride and silica, the amount of nano-silica to be added is very small. Nano-silica acts as a multi-functional additive. Upon addition of nano-silica to cement slurry, there is a decrease in the thickening time, an increase in the compressive strength, decrease in porosity and permeability within the cement and also a decrease in the fluid loss. Incorporation of nano-silica ensures proper cementation and greater integrity of the well. Nano-silica helps in decreasing the wait on cement (WOC) time and therefore reduces the overall capital cost. Nano-silica is highly recommended for deep offshore wells where high temperature and high pressure are often encountered. This paper discusses the behavior of Nano-silica at high temperatures and also reviews effects of Nano-silica on various properties of cement.

A Survey of Field Experiences With Formate Drilling Fluid

Summary High temperatures and wellbore-integrity issues are often encountered when drilling onshore and offshore wells. Formate drilling fluid was initially developed in the 1990s to battle high temperature. Field applications of formate mud have increased since the 2000s. This paper presents worldwide implementations of formate drilling fluid, including field cases in Canada, the North Sea, Germany, the Middle East, and Russia. Experiences with formate mud in Chinese fields that were previously unknown because of the language barrier are also reported. Most field cases reported high rate of penetration (ROP), excellent wellbore stability, good thermal stability, and high production rates upon completion. Reclamation and reuse of formate have significantly improved the cost–effectiveness of formate mud. In the current drilling industry, formate fluid has become one of the best choices for battling high–temperature and wellbore–stability issues.

Application of petrophysical methods to estimate total organic carbon in Lower Jurassic source rocks from the offshore Lusitanian Basin (Portugal)

Lower Jurassic outcrops in the westernmost part of the Lusitanian Basin (São Pedro de Moel area, Portugal) reveal three stratigraphic units with source rock potential: i) Unit F from the Coimbra Formation, ii) the Polvoeira Member of the Água de Madeiros Formation, and iii) the Marly Limestones with Organic-rich Facies Member of the Vale das Fontes Formation. Despite decades of research, these source rocks have not yet been characterised in the offshore areas of the Lusitanian Basin.As a consequence of the discrepancy between organic matter contents in correlative surface-subsurface intervals, this paper investigates the applicability of petrophysical methods to semi-quantitatively estimate total organic carbon (TOC) and delineate source rock intervals in Lower Jurassic (Sinemurian–Pliensbachian) units in the offshore Lusitanian Basin. This study is based on the i) high-resolution stratigraphic correlation between well 14A-1 and the São Pedro de Moel section and ii) calibration of the TOC curve calculated for well 14A-1 using the high-resolution TOC datasets from São Pedro de Moel.Sonic transit time vs resistivity cross-plot shows that several intervals of the aforementioned lithostratigraphic units deviate from the (organic) lean sediment baseline, interpreted to indicate the presence of hydrocarbons and low-density organic matter. Thermal maturity from cuttings samples were used to estimate vitrinite reflectance for each well point measurement. These values vary between 0.51 and 0.87, indicating that the studied interval has reached the oil generation window. The level of organic metamorphism is in accordance with the hydrocarbon generation window interval, varying between 9.49 and 9.76. Neutron/resistivity, density/resistivity, and sonic/resistivity cross-plots and the petrophysical-based method for TOC calculation outlined in Passey et al. (1990) demonstrate the close similarity between TOC curves calculated for well 14A-1 and TOC measurements from the São Pedro de Moel outcrops. This comparison highlights the organic-rich nature of Unit F, the Polvoeira Member and the Marly Limestones with Organic-rich Facies Member in the offshore areas of the Lusitanian Basin and their potential as hydrocarbons source intervals.This work demonstrates a feasible solution to semi-quantitatively estimate TOC in subsurface source rocks when there is large uncertainty regarding sample quality. Delineation of source rock intervals in the offshore wells of the Lusitanian Basin reduces uncertainty, minimises risk, and may aid in new exploration concepts for hydrocarbons offshore Portugal. On a broader scale, this work reinforces the importance of outcrop control to correlate and improve the current knowledge of Portugal's offshore areas.

The Effect of Resin-Coated Proppant and Proppant Production on Convergent-Flow Skin in Horizontal Wells With Transverse Fractures

Summary In the last decade, many gas reservoirs with permeabilities from 0.1 to 10 md have been developed with horizontal wells with transverse fractures. The potential negative effect of convergent flow in the fractures seems to have been forgotten. The widespread use of resin-coated proppant (RCP) in offshore wells appears to make this problem worse. Using both case studies and reservoir simulations, we examine why RCP could make the problem of convergent flow worse compared with uncoated proppant. Several North Sea horizontal and deviated multifracture gas wells that used RCP and had a significant mechanical skin are presented. Pressure-buildup data confirm the presence of a near-wellbore pressure drop in the fractures. Reservoir simulation with a fine grid reproduces the observed pressure drop because of convergent flow, using realistic proppant-pack permeabilities with gel damage. The effect of proppant production on the convergent-flow skin is shown using production data before and after discrete proppant-production events, demonstrating how proppant production has a beneficial effect on removing convergent-flow skin. We also compare the performance of a new horizontal multifracture well to the original discovery well in the same location, in which a vertical well was fracture stimulated with uncoated proppant and had comparable productivity. If there is a large convergent-flow skin in a fracture with uncoated proppant, this usually leads to some proppant production, which could create “infinite conductivity” channels at the perforations. This removes the convergent-flow pressure drop. If RCP is used to prevent proppant flowback, such channels cannot form easily, and convergent flow acts as a downhole “choke” on production. This “choke” can produce a significant positive skin. In the worst case, a horizontal multifracture well with three or four transverse fractures can produce the same as a fully perforated vertical well with a single fracture. On the basis of a number of real-world incidents of proppant production during post-fracture cleanup, we show strong evidence that a small amount of proppant production can result in an increase in well productivity index (PI) and a decrease in apparent fracture skin. Convergent flow is the most likely mechanism to explain this. In this paper we highlight the potential reduction in well productivity from using RCP for fracturing in gas wells (0.1 to 10 md) with limited inflow area (transverse or oblique fractures), where convergent-flow pressure loss is significant. We show the potential positive effect of small amounts of proppant production in such cases, forming infinite-conductivity channels and removing the convergent-flow skin.

Pore and fracture pressure modeling using direct and indirect methods in Badri Field, Gulf of Suez, Egypt

Abnormal formation pressure is one of globally dominant drilling hazards because of its direct impact on the drilling operations and exploration risk. An adequate pore pressure and fracture gradient modeling are considered the heart of the well planning and execution. Safe drilling to reach total depth of any well is the main concern for both engineers and geoscientists. Consequently, the main objectives of this paper are evaluation of pore pressure and fracture gradients as well as identification of the geo-pressured zones (over-pressured) in the subsurface sedimentary section.The pore pressure and fracture gradients were evaluated using well logging data namely density, resistivity, gamma-ray and sonic logs obtained from offshore wells in Badri Field. The overburden (overburden stress) was calculated using Amoco overburden equation, while sonic and resistivity logs were used for pore pressure and fracture gradient calculations using Eaton's method.The results of this study revealed that: 1) integration of direct and indirect method can lead to adequate and accurate pore pressure modeling; 2) pore pressure regime shows over-pressured, normal pressure and sub-normal horizons; 3) over-pressured zones was detected in the base of Zeit Formation, South Gharib Formation, Hammam Faraun Member and Kareem Formation, pore pressure were 10.3, 10.5, 9.3 and 9.6 ppg equivalent density in arrange; 4) Reservoirs of Hammam Faraun Member and Kareem Formation indicated Sub-normal pressure zones where pore pressure values are varying from 5.5 to 6.2 ppg for Hammam Faraun reservoir and from 5.2 to 8 ppg in Kareem Formation in equivalent density; 5) Normal pressure regime was detected in the upper part of Zeit Formation and Feiran, Sidri and Baba members, where pore pressure value was recorded as 8.7 ppg; 6) Best fitting parameter for Eaton resistivity and sonic logs are 0.9 and 1.65 respectively while for Amoco overburden empirical equations, the Amoco exponent best fit is 0.85 where the mud line density is 2.15 g/cm3. Finally, it is highly recommended to use low mud weight against the under compaction zones and high mud weights against the identified over-pressured intervals.

OH defects in quartz as a provenance tool: Application to fluvial and deep marine sediments from SW Japan

Hydrogen-related point defects (OH defects) in the crystal lattice of detrital, monocrystalline quartz have been proposed as an indicator to distinguish different sediment sources, making it a potential tool for provenance analysis. This study tests this novel technique on samples from SW Japan by comparing the results of OH defect analyses with those of “classical” provenance studies. OH defects of 188 detrital, monocrystalline quartz grains from five rivers (Fuji, Tenryu, Nagara, Yoshino, and Shimanto) and four offshore wells drilled in the Nankai Trough area (ODP site 1177; IODP sites C0002, C0007, C0012) are characterized using Fourier-transform infrared (FTIR) spectroscopy. Considerable differences in OH defect concentrations are identified between individual river samples. A general increase of values from east to west is observed. Possible links to the respective source geology are established. Very low OH defect contents (<1 wt. ppm water) of sediment from the Fuji and Tenryu rivers may be a result of high deformation and exhumation in the Izu-Honshu collision zone. Moderate to high OH defect contents of Nagara and Yoshino river samples (up to 50 wt. ppm water) are similar to the values of the global average in continental crust, possibly due to a mixing of various source lithologies. High and very diverse OH defect contents of Shimanto River sediments (up to 211 wt. ppm water) are likely an effect of extensive sediment reworking and mixing in the Nankai accretionary wedge. The OH defect signal is shown to be traceable through the offshore sedimentary record. In the western Shikoku Basin (ODP site 1177), turbidite deposits at 15 Ma and 7 Ma show a very similar signal as recent Shimanto river sediment, whereas eastern Shikoku Basin sediments (IODP Site C0012), at 15 Ma and 6 Ma strongly resemble present day Nagara and Yoshino river sediments. Sediments deposited in the Nankai trench wedge at 1 Ma (IODP Site C0007) indicate a shift towards lower OH defect concentrations. This may be due to increased, trench parallel sediment flux from the low-OH defect Fuji and Tenryu river sources, as proposed by previous studies. This study presents the first OH defect dataset in detrital quartz from rivers and offshore drill sites in a subduction zone environment, introducing OH defects as a new useful tool for sediment provenance analysis in active convergent margin settings.