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.
Fresh formation waters in the Wassana field, Gulf of Thailand, with water salinity as low as 1000 ppm NaCl equivalent, present a challenging environment in which to make perforation decisions based on the deterministic petrophysical interpretation from triple combo logs alone. To address the uncertainties on reservoir quality and fluid typing, NMR with multi-frequency and multiple depth of investigation (DOI) was planned early on in the development drilling. The Magnetic Resonance Fluid characterization (MRF) maps at three DOIs characterized the signature of synthetic oil base mud (SBM) filtrate invasion. The SBM invasion also facilitates the water signal identification and assists in quantifying the native oil viscosity.
In an early development well in Wassana field, 3 out of the four sands exhibit similar characteristics on logging while drilling (LWD) logs (
MRF maps at multi-DOIs reveal the second sand from top has a mobile water phase. At the shallowest DOI, the bound water, free water and SBM signals are observed on the map, as DOI increases, free water volume increases. The fluid characters on the maps are very similar to the maps acquired for a known water bearing sand just above the targeted "oil bearing" sands.
An integrated petrophysical interpretation shows that the other three sands in this sequence are oil bearing. SBM filtrate signals are observed at the shallowest DOI, as the DOI increases, the fluid signal shifts slightly to the left side of the SBM filtrate signal, at the deepest DOI, which is 4 inch from the borehole wall, the native oil signal dominates. Those three oil bearing sands were perforated with confidence, this well came on production at 790 BOPD and free of water.
Before undertaking any seismic interpretation project, it is essential to understand the rock physics of the area so that the interpreter knows what to look for in their seismic. Rock physics modelling can be used to predict the effects of lithology, fluid, porosity, depth and sand thickness on the seismic response. It can also help to understand whether direct hydrocarbon indicators (DHIs) such as flat spots, bright spots, dim spots or polarity reversals are expected and also the best seismic attributes to use to identify hydrocarbons. Well ties can be used to determine the quality of the seismic data and infer how reliably predictions based on the rock physics can be applied back to the seismic data.
The rock physics of several producing assets across the Gulf of Thailand have been examined and compared. Rock properties of over 200 wells have been analyzed based on stratigraphy, lithology, fluid fill, facies, porosity and depth. It was observed that the rock physics could be split into two distinct regimes based upon depositional environment separated by a key unconformity.
The first rock physics regime is observed in the shallow high porosity fluvial systems found within the Nong Yao Field and the younger reservoirs of the Jasmine and Manora Fields. In this regime, seismic attributes and seismic inversion have been successfully used to predict sand presence and thickness. Sands and shales have distinctly different rock properties and sands produce a strong class III-IV Amplitude Varation with Offset (AVO) response. Fluid effects can be observed on seismic although it is difficult as thickness and porosity changes may be incorrectly interpreted as fluid changes. The second rock physics regime is observed in the older, lower porosity lacustrine system found within the main reservoirs of the Manora Field and the pre-MMU reservoirs of the Jasmine Field. Within this regime, lithology prediction is much more difficult as sands and shales have very similar properties. Sands are modelled to have a class I-II AVO response and fluid effects are minimal.
Understanding the rock physics of these fields allows future work to be focused appropriately. At the Nong Yao Field and in the younger section of the Jasmine Field, technical work is focused on seismic inversion, seismic attribute analysis and other geophysical techniques for lithology and fluid prediction. Whereas at the Manora Field and in the older reservoirs of the Jasmine Field, technical work is focused more on structural mapping and geological modelling, and amplitude analysis is of lower priority.
Edwards, Maurice (Mubadala Petroleum) | Watcharanantakul, Rattana (Mubadala Petroleum) | Saifuddin, Farid (Mubadala Petroleum) | Yusuf, Mukminin (Mubadala Petroleum) | Nuada, I Nengah (Mubadala Petroleum) | Triandi, Muhammad (Mubadala Petroleum) | Trekarnjanavong, Thanakom (Mubadala Petroleum) | Jedsadawaranon, Panit (Mubadala Petroleum) | Doogue, Jacob (Schlumberger) | Thanh, Phung Nguyen (Schlumberger) | Santoso, Gagok (Schlumberger)
In many infill development scenarios, including those in shallow, heavy oil intervals, horizontal wells are required, and are positioned as high as possible within the reservoir. In other cases, horizontal wells are drilled to tap undeveloped oil in thin reservoirs with high uncertainty due to seismic resolution limitations. Mubadala Petroleum successfully deployed a new advanced Geosteering technology to overcome these technical challenges.
Although Geosteering is often conducted in this Mubadala Petroleum Field, there was a need to mitigate the additional complications of well positioning in complex fluvial reservoirs using innovative approaches and technologies. The solution was a new multi-layer bed boundary detection scheme using a deep azimuthal resistivity distance-to-boundary tool. This was coupled with a novel sophisticated high definition stochastic seismic inversion, providing the ability to resolve multiple bed boundaries above and below the tool, clearly understand formation dip and improve understanding of the boundary azimuth angle.
We present two case studies illustrating different applications of the new technology: The seismic inversion provided a clear image of the reservoir sand, however the new multi-layer bed boundary detection technology enhanced the ability to steer through the structural heterogeneous variations in the upper parts of the sand normally beyond seismic resolution of the data. The multi-layer bed boundary detection with high definition inversion provided valuable insight during the real-time horizontal drilling, which helped in maintaining the well in 75% high quality reservoir pay zone. For the horizontal drilling of the thinnest part of the reservoir where pre- and post-conventional seismic inversion volumes were insufficient to provide detailed stratigraphic and geometrical images, we successfully used the new technology to overcome the difficulties. In this approach and after landing the horizontal well into the sand, multi-layer bed boundary detection was used to navigate through the channel sand and maintain the well within the reservoir. This was assisted by streaming real-time high-definition stochastic inversion into the asset team's G&G software, which provided a highly accurate sand thickness, revising pay sand thickness from 15 feet to 25 feet and improving the accuracy of the volumetric estimation. As a result, the horizontal section was successfully navigated in 100% of the section and within high quality reservoir. Furthermore, we used this accurate data for a post-job recalibration of seismic and updating of the geological model and hence improving reserves estimation accuracy.
The seismic inversion provided a clear image of the reservoir sand, however the new multi-layer bed boundary detection technology enhanced the ability to steer through the structural heterogeneous variations in the upper parts of the sand normally beyond seismic resolution of the data. The multi-layer bed boundary detection with high definition inversion provided valuable insight during the real-time horizontal drilling, which helped in maintaining the well in 75% high quality reservoir pay zone.
For the horizontal drilling of the thinnest part of the reservoir where pre- and post-conventional seismic inversion volumes were insufficient to provide detailed stratigraphic and geometrical images, we successfully used the new technology to overcome the difficulties. In this approach and after landing the horizontal well into the sand, multi-layer bed boundary detection was used to navigate through the channel sand and maintain the well within the reservoir. This was assisted by streaming real-time high-definition stochastic inversion into the asset team's G&G software, which provided a highly accurate sand thickness, revising pay sand thickness from 15 feet to 25 feet and improving the accuracy of the volumetric estimation. As a result, the horizontal section was successfully navigated in 100% of the section and within high quality reservoir. Furthermore, we used this accurate data for a post-job recalibration of seismic and updating of the geological model and hence improving reserves estimation accuracy.
This is the first Mubadala Petroleum implementation in this basin of multi-layer bed boundary detection and streaming high definition stochastic inversion, providing vital information to real-time execution and to post job improvement of the field model.
Pulse neutron capture (PNC) is an effective technique to monitor lateral and vertical saturation/sweep. Assessing pulsed neutron results in either open-hole (OH) or cased-hole (CH) is key in evaluating formation properties, while with reservoir performance routinely monitored, time lapse logs are compared with the base logs to dynamically assess saturation changes and sweep efficiency.
PNC sensitivity to factors such as invasion, bore-hole and cement; makes its result influenced by rock matrix and fluid properties. LWD logging may minimize the mud filtrate impact; however this is subject to the drilling parameters and exposure.
LWD PNC has been analysed (drill and wipe pass) in both oil and water base muds. Quality assessment is performed on LWD/WL Sigma considering: mud used, invasion, formation water and mud properties. Variable Sigma was used to improve PNC saturation interpretation particularly within the transition zone. The effect of mud was discussed with examples showing its impact on data properties.
WL PNC time lapse logging over five years were analysed, results indicated mud dissipation process masking formation response. Resistivity and pulse neutron saturations are compared. PNC saturation is integrated with resistivity based saturation.
The capability of the pulsed neutron logging to derive meaningful results within the studied fields were examined in both OH, and CH conditions along with the definition of base log and the parameters used to derive saturation. Variable Sigma concept and uncertainty within transition zone is discussed. The used methodology and integration has improved the interpreted saturation, consequently enhanced the reservoir management.
The data used within the paper comes from two different carbonate fields' of complex, heterogeneous pore structures, and diverse mineralogy, allowing generic approach to the drawbacks seen.
Exploration in Thailand’s offshore Tertiary basins is hampered by the perception that the exploration efforts have reached a mature stage and by increased difficulties related to environmental approvals and stakeholder relations.
Petroleum activities in Mubadala Petroleum’s concessions in the GoT, although not situated close to the coast, are subject to review by a wide range of stakeholders, including coastal communities, local and national administrations and institutions, and NGO’s. At the same time technical work has revealed the possibility of exploration upside, but proving this potential, in addition to the nearly 7.5 BBOE already found, depends on a license to operate and therefore CSR approach and execution are key.
We will demonstrate that, while developing a prospect inventory based on innovative play types and complex/subtle trapping models, with combined structural and stratigraphic elements, we also developed a timely, clear and transparent CSR approach, which focuses on local needs combined with active stakeholder engagement by working in partnership with communities, local administrations and organizations on a tiered, repeatable and sustainable long-term footing. There is strong and genuine synergy between an exploration agenda which focusses on play and trap types away from the conventional faulted 3-way in heavily dissected and compartementalised traps concept, and CSR partnering initiatives. Failure to focus on both is restrictive and disadvantageous as they are genuinely complementary.
In our view Thailand’s perception of exploration maturity may be more related to the operational approach to finding hydrocarbons, rather than actual depletion of the resource. We will illustrate the exploration potential with a regional and biostratigraphic recalibration and with examples of complex play-trap systems and will demonstrate how we are successfully engaging with coastal communities and institutions to address socio-economic, educational and environmental challenges facing the communities around our operations in the GoT.
Exploration in the Gulf of Thailand (GoT) started in the early 1970’s and peaked in the 1990’s. The Pattani and Malay Basins are home to the majority of Thailand’s petroleum resources, but valuable resources have also been discovered in smaller peripheral basins (figure 1). Cumulative 2P resources discovered in the GoT amount currently to some 7.5 billion barrels oil equivalent, but creaming curves from the two main basins are showing a clear “mature” signature as volume additions by exploration drilling since the late 1990’s have been modest.
Petroleum production started in 1981 and has continued to grow up to 2012, but over the past 10 years this has mainly been a result of bringing earlier discovered fields into production, development of marginal accumulations, field life extension projects and infill drilling campaigns. Operators are increasing overall gas production by intensive infill drilling, planning close to a thousand wells in 2014.
Oglesby, Chris Alan (Mubadala Petroleum Thailand) | Boardman, David William (Mubadala Petroleum Services) | Edwards, Maurice (Mubadala Petroleum Thailand) | Saifuddin, Farid (Mubadala Petroleum Thailand) | Platt, Christopher (Mubadala Petroleum Thailand) | Limniyakul, Theeranun (Mubadala Petroleum Thailand) | Watcharanantakul, Rattana (Mubadala Petroleum Thailand) | Henneberg, Hans Peter (Mubadala Petroleum Services) | Tabmanee, Piyatad (Mubadala Petroleum Thailand) | Maneejan, Raweewan (Mubadala Petroleum Thailand) | McClure, Jason (Mubadala Petroleum Thailand) | Reverdito, David (Mubadala Petroleum Thailand) | Ionnnikoff, Yarick (Mubadala Petroleum Thailand)
The Jasmine Field began production in 2005 with initial estimated recoverable reserves of 7 MMbbls. Appraisal continued after the initial “A” platform commenced operation resulting in significant reserve growth that allowed for the installation of four additional production platforms (B, B1, C and D) and one remote platform, Ban Yen “A”, which began production in 2008. The Jasmine (and Ban Yen) Field was developed via deviated wellbores from the various platforms and was considered fully developed by late 2009. Oil production declined rapidly, accompanied by rapidly increasing water cut; leading to the perception of a short economic field life (in 2009 the end of field life was expected during 2012).
Since 2009, Mubadala Petroleum has been engaged in an active infill campaign, drilling 44 infill wells and 3 delineation wells. Delivery of this successful infill programme resulted from:
The success of this endeavor is such that a 50 MMbbls production milestone was passed in November 2013 and end of field life continues to increase through the use of improved engineering, science and technology.
The Jasmine Field, which is operated by Mubadala Petroleum and predecessor Pearl Energy, is located in the northern Gulf of Thailand and is the northernmost producing field in the prolific Pattani Basin (Fig 1). The field was discovered on 2D seismic data by Amoco and partner Idemitsu in 1974 with the drilling of the 6-2-L well, which tested oil from several zones. This well was drilled with a water-based mud system and the log quality is poor, indicating roughly 50’ of pay. Three DST’s were conducted on the well, one of which flowed oil at 770 bopd. Amoco drilled a follow up well in 1977, the 5-1-L, which was substantially off structure but had 14’ of pay that tested 107 bopd (Fig.2).