Baker Hughes drilled one horizontal well for major Indian operating company in a, low resistivity contrast field, onshore India. The candidate field / basin is a proved petroliferous basin, located in the northeastern corner of India.
The scope of work for this project involved integrating geological and open hole offset parameters to build a Geosteering model. Integrated data included a study of offset well data from the field, regional and local dip analysis from wellbore images, and a review of structural maps. Successful integration of these data helped to steer the well in the desired zone as per plan and make the best use of the data and to reduce uncertainties in Geosteering, drilling. Although high-quality 16-sector images commonly yield bedding dip, fracture and other geological information, this paper emphasizes how real-time reservoir navigation decisions was made using Geosteering modelling, real-time image processing, dip picking study etc.
Merza Media, Adeyosfi (Schlumberger) | Muhajir, Muhajir (Pertamina Hulu Energi Tuban East Java) | M. Wahdanadi, Haidar (Joint Operating Body Pertamina Petrochina East Java) | Agus Heru, Purwanto (Joint Operating Body Pertamina Petrochina East Java) | Anugrah, Pradana (Schlumberger) | Dedi, Juandi (Schlumberger)
Most of sedimentary basins in Indonesia contain productive carbonate reservoirs. Geologically, the reservoirs are mostly part of a reef complex and carbonate platform, with basinal areas situated mainly in the back arc of the archipelago. Many of the productive carbonate reservoirs have dual porosity systems with widely varying proportions of primary and secondary porosity. Carbonates of the Tuban formation in Platinum field represent two carbonate buildups identified with similar effective porosity but different productivity. This paper describes a method for characterizing secondary porosity distribution at the wellbore and field scales to address the productivity difference between the northern and southern carbonate buildups in this field.
To resolve the challenges in characterizing secondary porosity in a carbonate formation, an integrated workflow was developed that consists of combination of quantitative and textural analysis based on borehole images at the single-wellbore scale and the seismic inversion result to control lateral distribution at the field scale. Analysis based on borehole image log provides high-resolution porosity characterization based on its size, interconnectivity, and type. The result of the single-wellbore analysis will be distributed at the field scale with control of a seismic attribute such as acoustic impedance (AI). Acoustic impedance is built with stochastic seismic inversion to provide a higher-resolution result compared to the deterministic seismic inversion method.
The result of the analysis based on borehole images at the single-wellbore scale shows most of the northern carbonate buildup wells demonstrate high development of porosity from interconnected vugs, leading to a relatively high permeability interval. In contrast, the southern carbonate buildup wells demonstrated low secondary porosity development. Low secondary porosity development is related to cemented zones and the predominance of claystone facies in a well. Later, the result of the single-wellbore scale analysis was distributed at the field scale with seismic attribute control such as AI. The Platinum field shows a negative correlation between AI and porosity with a value of -0.769; hence, the acoustic impedance from stochastic seismic inversion can be used to control the porosity distribution. The secondary porosity model shows a distinct difference between the northern and the southern carbonate buildups. The northern carbonate buildup has higher average secondary porosity compared to the southern carbonate buildup. The result was confirmed with production data; the northern carbonate buildup has higher productivity compared to the southern carbonate buildup.
This integrated workflow provides a comprehensive and high-resolution analysis of secondary porosity distribution at the single-wellbore scale and the field scale. Thus, this workflow can reduce uncertainty during reservoir characterization, well placement, and production planning.
Structural dip is the term used in borehole image and dipmeter interpretation to indicate the "tectonic" tilting in the vicinity of the wellbore. Structural dip, by definition, is the formation dip component that is caused by tectonic deformation such as folding, faulting, uplift and others.
Knowledge of the structural dip in the vicinity of the borehole is essential for several applications, including field structural modeling, well placement, geosteering of the lateral sections, and seismic data processing.
Traditionally, structural dip is computed from borehole image data using laminated shale dip based on the assumption that the laminated shale was deposited out of suspension and that the lamination was originally deposited as horizontal beds. This means that any tilting observed in laminated shale with "coherent" lamination is caused by tectonic tilting; hence, it can be used to compute the structural dip. There is nearly a consensus in the industry around this assumption, and the laminated shale dip is widely used to compute structural dip.
There are several geological settings under which laminated shale can form. Those are mostly subaqueous setting such as marine and lacustrine settings. Drilling through rocks deposited in such settings normally encounters sequences of laminated shale from which structural dip can be computed. However, rock formations deposited in subaerial environments often lacks settings under which laminated shale forms. Such environments are often dominated by sandstone lithologies deposited in high- energy settings this rich in sedimentary structures such as crossbedding. Due to absence of laminated shale sequences, computation of structural dip using the traditional approach is not possible.
This paper explains a technique that can be used to estimate structural dip from cross bedding on borehole images. It uses the geometrical relationship between the crossbedding surfaces and the lower set boundary of the corresponding crossbedding set. The line of intersection between these two surfaces is assumed to be horizontal at the time of deposition. Measuring multiple lines of intersections, plotting them on a stereonet, and fitting a great circle to them helps estimate the structural dip within the analyzed interval. The best- fitting great circle of these lines is believed to be a reasonable estimation of the structural dip.
This approach has been tested on few image log datasets with cross bedded sandstone facies and proved to be very close to the actual structural dip computation obtained from the shale facies in the same depositional sequence. This paper will illustrate some interpreted image log supporting this technique.
Hu, Haitao (CNPC Logging Co. Ltd. Research Institute of Logging Technology) | Xiao, Zhanshan (CNPC Logging Co. Ltd. Research Institute of Logging Technology) | Zhao, Baocheng (CNPC Logging Co. Ltd. Research Institute of Logging Technology) | Yu, Zhennan (CNPC Logging Co. Ltd. Research Institute of Logging Technology) | Zhu, Ruiming (CNPC Logging Co. Ltd. Research Institute of Logging Technology) | Liu, Jianguo (CNPC Logging Co. Ltd. Research Institute of Logging Technology)
Focused borehole to surface electric imaging is researched through numerical simulation in this study, this method makes downhole electrical logging synchronize with three dimensional space electrical exploration near the well, and combines borehole electrical logging with surface electrical prospecting, which can expand spatial scale of well logging evaluation technology and increase vertical resolution of borehole to surface electric imaging evaluation technology. This method can be used for detecting the geological information around well and between wells and wells. It provides a new means for exploration of residual oil distribution and evaluation of unconventional reservoirs fracturing effect. In this method, a new electrode structure, multi frequency focused high power transmission mode and surface reception modes are adopted. Based on the three dimensional finite element numerical simulation method, the instrument response characteristics in homogeneous formation and in homogeneous formation are analyzed. The influences of electrode depth, electrode length, and current return electrode orientation on surface potential distribution are analyzed. The results indicate that borehole to surface electric imaging system can effectively identify formation resistivity anomalies. The larger the spatial scale of resistivity anomaly, the better the recognition effect. Under certain conditions, downhole emission electrode depth is inversely proportional to surface potential distribution distortion, and downhole emission electrode length is proportional to it. When current return electrode B is placed far enough from the wellhead, the influence of electrode B orientation on surface potential distribution is negligible.
Amer, AimenAi (Schlumberger) | Sajer, Abdulazziz (Kuwait Oil Company) | Al-Adwani, Talal (Kuwait Oil Company) | Salem, Hanan (Kuwait Oil Company) | Abu-Taleb, Reyad (Kuwait Oil Company) | Abu-Guneej, Ali (Kuwait Oil Company) | Yateem, Ali (Kuwait Oil Company) | Chilumuri, Vishnu (Kuwait Oil Company) | Goyal, Palkesh (Schlumberger) | Devkar, Sambhaji (Schlumberger)
Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes.
Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network.
This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production.
The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors.
Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.
A new LWD ultrasonic imager for use in both water- and oil-based muds uses acoustic impedance contrast and ultrasonic amplitude measurements to obtain high-resolution structural, stratigraphic and borehole geometry information. Following extensive testing in the Middle East and the US, this paper presents results from the first European deployment of the new 4.75-in. high-resolution ultrasonic imaging tool.
An ultrasonic transducer, which operates at high frequency, scans the borehole at a high sampling rate to provide detailed measurements of amplitude and traveltime. A borehole caliper measurement is made, based on the time of arrival of the first reflection from the borehole wall. A second measurement detects formation features and tectonic stress indicators from the change in signal amplitude. The amplitude of the reflected wave is a function of the acoustic impedance of the medium. Resulting impedance maps have sufficient resolution to detect sinusoidal, non-sinusoidal and discontinuous features on the borehole wall.
Breakouts, drilling-induced fractures, and tensile zones were used for stress direction determination. Breakout identification was obtained both from amplitude images and oriented potato plot cross sections derived from traveltime measurements.
The orientation of natural fractures is parallel at the maximum stress direction, indicated by drilling-induced fractures and tensile zones. The World Stress Map confirms the maximum stress direction determination.
It was also possible to detect certain key-seat zones and investigate borehole conditions to prevent issues during the subsequent casing job.
The new LWD ultrasonic imaging technique represents an important alternative to density and water-based mud resistivity imaging, which has several limitations. Unlike the resistive imaging LWD tool that is very sensitive to standoff, the higher tolerance of the ultrasonic imaging tool enables the amplitude and traveltime ultrasonic images to contain fewer unwanted artifacts.
BinAbadat, Ebtesam (ADNOC Offshore) | Bu-Hindi, Hani (ADNOC Offshore) | Lehmann, Christoph (ADNOC Offshore) | Kumar, Atul (ADNOC Offshore) | AL-Harbi, Haifa (ADNOC Offshore) | AL-Ali, Ahmed (ADNOC Offshore) | Al Katheeri, Adel (ADNOC Offshore)
In this study, core and log data were integrated to identify intervals which are rich in stromatoporoids in an Upper Jurassic carbonate reservoir of an offshore green field Abu Dhabi. The main objective of this study was to recognize and stromatoporoids floatstones/rudstones in core, and develop criteria and workflow to identify them in uncored wells using borehole images.
The following workflow was used during this study: i) Identification of the stromatoporoid feature in pilot wells with core and borehole images, ii) Investigate the properties and architecture of stromatoporoid bodies, iii) Integrate the same scale of core observations with borehole images and conventional log data (gamma ray, neutron porosity and bulk density logs) to identify stromatoporoid-rich layers, iv) Performing a blind test on a well by using the criteria developed from previous steps to identify "stromatoporoid accumulations" on a borehole image, and validate it with core observations.
In the reservoir under investgation, stromatoporoid floatstones/rudstones intervals were identified and recognized both on core and borehole image in the pilot wells. These distinct reservoir bodies of stromatoporoids commonly occur in upper part of the reservoir and can reach to a thickness of around 20ft. The distribution and thickness of stromatoporoid bodies as well as growth forms (massive versus branching) were recognized on core and borehole images. The accumulations varied between massive beds of containing large pieces of stromatoporoids and grainstone beds rich in stromatoporoid debris. The massive beds of stromatoporoid accumulations are well developed in the northern part of the field. These layers can enhance the reservoir quality because of their distinct vuggy porosity and permeability that can reach up to several hundred of milidarcies (mD). Therefore, it is important to capture stromatoporoid layers both vertically and laterally in the static and dynamic model. Integrating borehole image data with core data and developing a workflow to identify stromatoporoid intervals in uncored wells is crucial to our subsurface understanding and will help to understand reservoir performance.
Integration of image log data which is calibrated to core and log data proved to be critical in generating reservoir facies maps and correlations, which were integrated into a sequence stratigraphic framework as well. The results were used in the static model in distribution of high permeability layers related to the distribution of stromatoporoids.
Warot, Gregory (Weatherford) | Wallace, Shawn (Weatherford) | Mostafa, Hassan (Weatherford) | Elabsy, Eslam (Weatherford) | Di Tommaso, Davide (Weatherford) | Abdelkarim, Aly (Weatherford) | Ciuperca, Constantin-Laurian (Weatherford)
Increased development of naturally and hydraulically fractured unconventional reservoirs from horizontal wells, drilled with oil-based muds, has created a need for high-resolution logging-while-drilling (LWD) borehole imaging tools capable of resolving fractures in this borehole environment. A new LWD ultrasonic borehole imager has been developed and tested to meet this need.
Borrowing from wireline ultrasonic imaging technology, a 250 kHz piezo-electric transducer was adapted to an LWD drill collar. The single transducer serves as both transmitter and receiver: transmitting an ultrasonic pulse, and measuring both the amplitude and two-way travel time of the acoustic reflection from the borehole wall. The LWD tool takes advantage of drill string rotation making a 360-degree scan of the borehole with a single fixed transducer. Finite element modeling and laboratory testing in artificial formations and a large limestone block were used to determine the spatial resolution of the image, as well as the sensitivity to downhole acquisition variables such as standoff, tool eccentricity, and mud attenuation. Prototype tools were then field tested in several horizontal wells to verify the functionality and image resolution under actual drilling conditions.
The borehole images from horizontal wells in unconventional and conventional reservoirs in the Middle East and the UK verified that tool responded as designed. These images, recorded in both oil-based and water based muds, revealed open and cemented natural fractures, drilling induced fractures and borehole breakout, fine-scale bedding, and other textural geological features such as vugs and stylolites. A variety of drilling-related borehole artifacts were also observed, including keyseats, stabilizer impressions in the borehole wall, tool marks from a rotary steerable tool, and gouges made by the bit rotating off bottom. The amplitude image proved more sensitive to fractures, bedding, and other geological features, while the travel time image, combined with input mud compressional velocity, provided a 360-degree borehole caliper image, showing the borehole size and shape.
Although high-resolution LWD electrical imagers have been available for years, these can only operate in conductive, water-based, muds. As most horizontal wells in both conventional and unconventional reservoirs are now drilled with oil-based muds, the development of a high-resolution ultrasonic imager capable of identifying natural and hydraulic fractures, fine-scale bedding, secondary porosity, and other small scale features in wells drilled with oil-based muds fills an important gap in LWD technology.
Al-Enezi, Bashar (Kuwait Oil Company) | Kostic, Boris (Badley Ashton & Associates Ltd) | Foote, Nicolas (Badley Ashton & Associates Ltd) | Filak, Jean Michel (Kuwait Oil Company) | Al-Mahmeed, Fatimah (Kuwait Oil Company) | Al-Shammari, Obaid (Kuwait Oil Company) | Bertouche, Meriem (Badley Ashton & Associates Ltd)
Resistivity image logs are high-resolution tools that can help to unravel the depositional and structural organisation in a wellbore. They provide a particularly powerful dataset when calibrated against core, maximising their benefit for reservoir characterisation. This paper shows examples how very detailed image assessment from selected wells in the Greater Burgan Field has helped to constrain the stratigraphic model and depositional interpretations of the Cretaceous Burgan and Wara reservoirs.
A multidisciplinary study of 123 cored wells, integrating core sedimentology, petrography, bio- and chemostratigraphy, wireline well and resistivity image logs, has delivered a robust stratigraphic and depositional framework for one of the most important reservoirs in the world's largest siliciclastic oil field. A descriptive image facies scheme that has been calibrated against core and conventional well logs captures the lithological variation, sedimentary features and surfaces of the reservoir, providing a detailed proxy for the sedimentological evaluation of uncored intervals and wells.
The sand-rich lower Burgan (4S) comprises fine to very coarse-grained fluvial channel sandbodies that are locally separated by laterally restricted mudrock baffles. Image and core analyses suggest that the majority of the sandstones are high-angle cross-stratified and form stacked barforms within amalgamated channel sandbodies. Their consistent orientation towards the NE-E supports a low-sinuosity (braided) fluvial system resulting in a relatively simple, sheet-like depositional architecture across the field. Although slightly finer grained, the cored middle Burgan channel sandbodies (3SM) are similar to those in the lower Burgan. However, palaeoflow data from the imaged wells show a higher directional spread in the order of
The examples from the Burgan and Wara Formations highlight the value of integrated image analysis for reservoir characterisation by delivering a consistent descriptive framework, embedding different datasets.
Noufal, Abdelwahab (ADNOC - Upstream) | Obaid, Khalid (ADNOC - Upstream) | Al Blooshi, Abdulla (ADNOC - Upstream) | Nehaid, Hani (ADNOC - Upstream) | Basioni, Mahmoud (ADNOC - Upstream) | Alward, Wassem (Schlumberger) | Uruzula, Jaja (Schlumberger) | Shamsal, Sudipan (Schlumberger) | Dasgupta, Suvodip (Schlumberger) | Raina, Ishan (Schlumberger) | Schlicht, Peter (Schlumberger)
Carbonate reservoirs of the Middle East are known for exhibiting highly heterogenous nature in terms of reservoir properties within microscopic intervals of the reservoir, making it difficult to characterize and predict. An integrated approach involving detailed understanding of the fluids volumes porosity distributions, permeability systems, rock textures, reservoir rock types, and natural fracture distribution at different scales is needed. Accurate characterization for the flow networks, complicated by fracturing and diagenesis is fundamental to achieving realistic prediction, better production performance, and increased recovery. The rock texture in carbonate reservoirs is very unstable and continuously undergoing to multiple stages of dissolution, precipitation, and recrystallization, which obscures any relationships that might have existed between depositional attributes, porosity, and permeability. Fractures make it more complex with their different morphology, often further convoluted by leaching through them. Different measurements are needed to build a realistic model of the petrophysical properties of a carbonate formation. The standard resistivity and porosity measurements are often not sufficient to resolve changes in pore size and texture, so additional measurements are required. Workflows using borehole images can be used to extract information on different textural elements and porosity types. With the newly introduced workflow secondary porosity types are distinguished from matrix porosity and proxies for permeability are calculated.
This workflow integrates borehole images and other petrophysical data in sequential steps and provides important reservoir parameters. With the suggested analytical workflow, it is possible to classify the different types of pore space such as connected to vugs (vug to vug), isolated, connected to fractures, aligned at bed boundaries, or within the rock matrix. The contribution of these different pore types to the total porosity of the formation is quantified in addition to the geometric information of different types of heterogeneities. In addition, the connectedness of the different types of porosity is quantified. The connectedness log describes the quantity of connected spots detected from the electrical borehole image and is used as a predictive measure for identifying zones of higher or lower permeability. During operation it serves as an indicator for determining the perforation intervals, in static reservoir modeling it serves as a permeability driver to improve reservoir mapping. We demonstrate an example where the connectedness successfully predicted productive zones, proven by production logging.