Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Easy oil is no longer low hanging fruit for oil and gas operators, and drilling targets are becoming increasingly ambitious, which results in escalation of the well trajectory complexity. This accordingly spirals the well and completion costs. To overcome this situation, technology must play a role to reduce cost, increase efficiency and ensure safety at all times. Conveyance is the key for any data acquisition and well completion activities. Historically, conveyance methods for data acquisition and perforation in highly deviated or horizontal wells required drill pipe or coiled-tubing methods. These methods are time consuming, labor intensive, require a larger equipment footprint, with possible HSE risks involved. Mubadala Petroleum in Thailand has seen a significant increase in horizontal and high deviated wells over the past few years. The wireline tractor technology has been used for the first time in Mubadala Petroleum's Thailand operations during the drilling, initial completion and workover intervention operations, and it has been a game changer for Mubadala Petroleum in Thailand in terms of reducing rig time, well cost, and most importantly minimizing the HSE risks.
Over the past few decades, the oil and gas industry has developed the technique of drilling horizontally through the reservoir to maximize the surface contact area of the reservoir, to gain higher recovery and production. However, one downside from this technique is that it has become challenging and costly to perforate or to obtain measurements in this horizontal environment, as gravity will no longer support the wireline tools to reach to the bottom of the well. Wireline Tractor technology has played an important role to overcome this challenge. It reduces time, cost and will improve data quality as well as increase wellbore coverage. The wireline tractor functions with an electric over hydraulic power relationship, using its drive/wheel sections to push the passenger tool downhole as the cable is spooled off the unit allowing the tool to reach the end of horizontal or deviated wells without deploying drill pipe or coiled tubing conveyance methods. With this principle, any job that is typically run on electric wireline in a vertical well can be efficiently done in a horizontal or deviated well using wireline tractor.
Material presented in the paper will be from actual operations, examples being tractor conveyed wireline logging tool and 4.5in Outer Diameter (OD) 90 ft heavy long perforation gun in single tractor operations. It will also display the operational efficiencies increases and risk reduction being obtained.
The Jasmine Field sandstone reservoir described in the paper is highly compartmentalized, has a sand thickness of about 30-40ft, reservoir pressure is supported by a strong aquifer, and most wells have high productivity. However, in the particular fault block of interest, a gas cap is present, which is normally not present in other fault blocks. This reduces the oil sand thickness to about 20 ft, with a big gas cap above and water below. To efficiently produce the oil rim in this area, a horizontal well was required, with an electrical submersible pumps (ESP) to aid lift. Since ESPs don't typically handle gas very well, the challenge was to ensure the well is economic by preventing premature gas breakthrough, and hence increase oil recovery.
The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil.When used in a horizontal well, segmented into multiple compartments, this device prevents excessive production of unwanted fluids after breakthrough occurs in one or more compartments. The JS-06 well was drilled with almost 2000 ft horizontal length within the original thin oil column, with gas on top and water below. AICD flow loop testing, performance modelling, candidate selection, and completion design for this well was focused on gas production control, given that gas production was the main concern.
Post implementation and production, gas production has been controlled very well compared to the base case conventional completion. The gas oil ratio (GOR) observed from nearby wells was within the normal production range, which has allowed more oil to be produced from the JS-06 well. The production results observed were consistent with modelling and laboratory flow testing, thereby increasing confidence in the methods employed in designing the AICD completion for the well and in AICD modelling and candidate selection.
The successful implementation of AICD in this well has opened up another similar opportunity, which are currently being evaluated for the same application
Amer, Mohamed Mostafa (ADNOC Offshore) | Serry, Amr Mohamed (ADNOC Offshore) | Afzal, Nusrat Afrin (ADNOC Offshore) | Al Zaabi, Fatema (ADNOC Offshore) | Al Jaberi, Salem (ADNOC Offshore) | Zhou, Jiheng (Baker Hughes, a GE Company) | Ismail, Mostafa (Baker Hughes, a GE Company) | Nada, Al Sayed (Baker Hughes, a GE Company)
Pulsed neutron logging is currently the most commonly used technology for cased hole formation saturation analysis, providing data for reservoir monitoring and management. The common pulsed neutron log measurement is the formation capture cross section (Sigma). The data can be logged at a relatively fast logging speed. Water saturation analysis using the Sigma log requires high porosity and known formation water salinity. Errors in the Sigma log interpretation can result from the uncertainties of water salinity values, which usually change, for example, due to mixing of the hypersaline formation brine with the low-salinity injected seawater. Heterogeneity and changes in the carbonate petrophysical properties also play a role in magnifying the magnitude of water salinity changes. Carbon/ oxygen ratio logging (C/O) is salinity-independent and can be applied to overcome the problem, but the physics of the measurement usually require multiple passes with lower logging speeds than Sigma logging. This paper introduces a novel pulsed neutron logging methodology to help overcome the mixed-water salinity problem and produce a reliable water saturation interpretation for updating fluid front maps.
First, the pulsed neutron tool was operated in Sigma mode to cover the full target reservoir interval in a single pass. The tool was then switched to the C/O mode with multiple passes for 50ft only at the top of the target reservoir. Monte Carlo modelling was applied to the C/O data to calculate the water saturation. The C/O result was then used with the Sigma log data to inversely calculate the Sigma water using a Sigma-based material balance equation across the same interval. The final water saturation across the full interval was estimated by using the calculated water salinity and the Sigma data.
Through the application of the proposed methodology, we successfully measure the target formation saturation information in an acceptable operating time, when compared to conducting the conventional C/O logging across the full interval. The results show that the estimated formation water salinity is close to that value of drilling mud filtrate; the water saturation is slightly lower than that from the openhole resistivity interpretation.
This paper introduces how to optimize a pulsed neutron logging program that combines the C/O and Sigma measurements to enhance the offshore operations efficiency, minimize the water saturation interpretation uncertainties, and support future field development planning.
Asia is the largest and the most populous continent in the world covering an area of 44,579,000 sq. Its 4.5 billion people form roughly 60% of the world's population. To understand the intricacies of this vast and diverse continent, it is a common practice to categorize the constituting countries as per the subject--economic development--under discussion. One such categorization is "Tiger Economies." It is the nickname given to the economies of Southeast Asia. The tigers are South Korea, Taiwan, Hong Kong, and Singapore.
Asia is the largest and the most populous continent in the world covering an area of 44,579,000 sq. Its 4.5 billion people form roughly 60% of the world's population. To understand the intricacies of this vast and diverse continent, it is a common practice to categorize the constituting countries as per the subject—economic development—under discussion. One such categorization is “Tiger Economies.” It is the nickname given to the economies of Southeast Asia. The tigers are South Korea, Taiwan, Hong Kong, and Singapore.
‘Play-based Pore Pressure Prediction’ is a new concept that considers overpressures and pore pressure prediction as being a fundamentally similar process to the ‘play-based exploration’ approach commonly used to search for hydrocarbons. For overpressures to exist, the right set of conditions needs to occur in the right order and timeframe. Just like a hydrocarbon play, overpressures need a source (generation mechanism), reservoir (the overpressured formation) and seal (ability to maintain overpressures over geological time). Current pore prediction methods do not consider overpressure over the geological timespan of a basin, and commonly result in overpressures being encountered in unexpected formations and depths, or at greater magnitude than anticipated, and has resulted in many drilling incidents.
Play-based pore pressure prediction involves undertaking pore pressure analysis in a similar holistic manner to how prospects are generated during hydrocarbon exploration. The process involves using basinscale geology to establish likely overpressure mechanisms and formations (akin to identifying sources, reservoirs and seals); determining timing of overpressure generation throughout burial history, and; identifying major events causing overpressure transfer or dissipation (akin to hydrocarbon generation, charge analysis and trap development). Regional concepts are used to develop models to determine the likely locations and magnitude of overpressure (akin to hydrocarbon fairways and plays). Finally, regional learning's are applied at the prospect scale to select the best methods to predict pressures for planned wells. The innovation, and added benefit, of this new and novel approach is that ‘play-based pore pressure prediction’ can also be used to identify successful new exploration plays. Herein, I present an example of ‘play based pore pressure prediction’ from the Malay Basin that was used to improve drilling safety, and developed a new play concept that has subsequently resulted in 3 successful discoveries.
The Jasmine Field is a mature stacked-sand oil field that has been on production since 2005. One of the biggest current challenges is to locate remaining oil accumulations. Seismic mapping, material balance and reservoir simulation studies provide pointers to promising locations, but can never guarantee accuracy. Pilot wells offer a means to appraise identified locations before committing to drilling horizontal wellbores.
A pilot well is often used in Mubadala Petroleum drilling campaigns as part of an overall strategy to extend the field's life by continuing to locate and tap remaining oil accumulations. Collaboration across subsurface teams leads to decisions on pilot well locations. In most cases the pilot well appraisal objectives will be to confirm the structural position, to identify fluid contacts or to assess depth uncertainty, especially in areas where there is no well penetration or in significantly updip locations. These appraisal objectives apply to shallower and deeper horizons as well as to the target reservoir itself, and in Jasmine there is a strong record of accomplishment of successfully locating remaining oil by means of such appraisal. It is critical therefore, that well planning is tailored so as to accommodate the appraisal objectives as well as the eventual production target.
Two case studies are presented, illustrating different approaches to using pilot wells prior to placing horizontal wellbores in Jasmine field. In the first case, the horizontal production wellbore was planned to develop an updip region of the target reservoir, to access remaining oil, with additional pilot well appraisal objectives in both shallower and deeper zones. The location for the new horizontal well was confirmed and this dual-role pilot/producer well not only succeeded in reducing depth uncertainty for the new horizontal wellbore, but also identified additional reserves in other reservoirs. In the second case an appraisal pilot well was used to investigate a downdip region of a depleted reservoir. Material balance assessment had indicated that the volume accessed by the updip producer was larger than suggested by the static model, which might have resulted in water encroachment from downdip, causing the appraisal location to water out. However, seismic imaging identified potential barriers between the updip and the proposed downdip appraisal location, which would have prevented water encroachment from downdip. The pilot appraisal well was required to distinguish between those two possibilities.
Detailed knowledge of fill-spill history and charge entry points to fields is rarely available, due to lack of suitable data sets and methodologies. This paper describes the application of a reservoir geochemical work flow (multi-variate statistical analysis of geochemical data) to unravel the fill history of a highly complex oil field in the northern Gulf of Thailand, and the implications of these results in assessing charge risk in adjacent and near-field prospects.
The Jasmine-Ban Yen field, Pattani Trough, Gulf of Thailand, produces from stacked Middle to Late Miocene clastic reservoirs, draped over a highly faulted structural nose. In an earlier study, 59 oils from across the field underwent standardised fingerprinting, biomarker and bulk isotope analysis. Here, geochemical parameters considered resistant to secondary processes such as biodegradation, underwent hierarchical cluster analysis and classification into fluid families. Distinct families potentially represent fluids that share a common history. The results were synthesised with spatial information, seismic data, reservoir pressures, petroleum systems modelling, and observations drawn from the field's production history, to elucidate the fill-spill history of the field.
All oils were expelled from similar lacustrine organofacies at similar maturity, which is broadly consistent with a single source pod charging the field. The closest mature kitchen is thought to be located in the Northern Pattani Trough, some 20 to 25 km to the south. A sub-regional Middle Miocene lacustrine seal, the "hot shale," focusses oil into the Jasmine-Ban Yen field, and forms the seal for 30% of the STOIIP. Fluids also occur in reservoirs above this seal, which could be emplaced either through vertical fill and spill via high offset faults, possibly aided by locally high CO2 increasing buoyancy pressure by formation of a gas cap, or laterally, via spill from adjacent fault blocks. Detailed knowledge of charge history remains elusive; however, the occurrence of consistently different fluid families above and below the hot shale seal, with fluids below represented by consistent families over a lateral distance of 12 km, supports an interpretation of multiple entry points into the field. Aromatic maturity parameters indicate that four Ban Yen samples are of slightly elevated maturity, suggesting that late charge accesses the field above the hot shale. The possibility that the differences between families are related to biodegradation was investigated and discarded. Families probably represent discrete, lateral spill pathways reflecting multiple charge entry points and are differentiated by subtle variations in organofacies related to oxicity and contribution from plant material. Comparable migration above and below the hot shale into B5/27 is a possibility, and exploration prospectivity is risked accordingly.
Placing statistically derived fluid families into a spatial, geological and production context enables unravelling of migration vectors in complex fields. Furthermore, inferences may be drawn from such a study that can help guide risk assignment to offset exploration prospectivity.
Horizontal well technology has been used in the Pattani Basin to target oil and gas reservoirs since the late 1990’s. As of today, the Chevron Operated B8/32 block and Platong fields have been producing from 70 horizontal wells. While about 80 % of the horizontal wells in Platong have been completed barefoot, the use of ICD’s has been increasing since 2010. Recently, in the Platong field, two ICD equipped horizontal wells were used initially for primary production of a major reservoir, following which one of the two wells was converted into a water injector to enhance total recovery from the reservoir.
The ‘Z’ reservoir located in Platong field has significant barrels (in the millions) of oil in place with an initial gas cap and a water leg. The reservoir was initially appraised and tested with a single deviated wellbore. This well confirmed the reservoir potential and identified gas and water coning, together with sand production as the major risks to optimising oil recovery. To manage potential oil and gas coning, a reservoir development plan, based around a pair of horizontal well completions, was developed. Both well completions were designed with sand control screens incorporating ICD’s to optimize inflow along each horizontal wellbore. The wells were drilled and completed in early 2012. After collecting surveillance data and modeling the primary production performance of the reservoir, a waterflood opportunity to increase total recovery was planned. The asset team implemented the in-situ conversion of one of the horizontal wells into a waterflood injector in August 2013. Response to the water injection has been confirmed in the second well of the pair and incremental oil of >50 MBO has been recovered.
This case study presents an analysis of the target reservoir, the development strategy and then captures the lessons learned from the performance of horizontal producers with ICD completions during primary production and during the later waterflood phase. The main challenges for future horizontal wells applications in Platong are relatde to thin fluvial sands and depletion. The use of ICD’s will continue to be proposed for new horizontal targets based on the positive incremental production impact.