The PEP structure in Matindok block in Central Sulawesi has been proven to produce gas reserves in the Minahaki formation based on the first exploration well PEP-001 that was drilled in 2018. The PEP structure has a Miocene carbonate build-up play, and the target reservoir is the M member pinnacle carbonate reef. One of the main challenges in this area is low resolution of seismic data, leading to a high depth uncertainty of top M position. The PEP-001 well was planned to set the 9 ⅝-in casing point above top M. Offset wells did not show any clear markers in the thick shale above M formation, that could have been used for log correlation. In previously drilled offset wells correlation was done conventionally by taking cutting samples and relying on drilling parameters break. However, when PEP-001 was drilled, no apparent drilling break was observed. By the time cuttings reached surface, the bit had drilled into 20-m thickness of M formation. Since casing covered most part of the upper carbonate formation, open hole logging and well testing data were not acquired to delineate target M formation optimally. The second exploration well PEP-002 was planned with an objective to set 9 ⅝-in casing ~5 m above top M to acquire a full interval coverage of coring, open hole wireline logging, and well testing program. This information was critical for optimal reservoir delineation to allow for accurate reserve calculation and future structure development. Conventional correlation (well-seismic pairing and correlation) has proven insufficient for casing point placement and was a lesson learned from PEP-001. The presence of limestone stringers observed in offset wells within proximity of top M presented an additional challenge. The stringers could have been mis-interpreted as the main carbonate body, if interpretation was solely based on cutting samples. Based on these challenges, a technology with the capability to map and detect lithology changes ahead of the bit in real time was required. Real-Time EM Look Ahead technology uses deep directional electromagnetic (EM) technique to detect formation feature ahead of the bit. A feasibility study was done to simulate the tool response and define the placement of transmitter and receivers (spacings) in the BHA, as well as frequency selection based on the resistivity properties from offset wells. Based on the simulation, this technology was expected to detect top M formation as early as 10 m ahead of the bit. While drilling, top M could be resolved at 6 m ahead of the bit with an uncertainty of <1 m, therefore making this the fit-for-purpose technology to place the 9 ⅝-in casing point ~5 m above the M formation. As a result, 9 ⅝-in casing was successfully placed 5 m above top M. High resistivity contrast, that is expected to be top M, was mapped continuously from 10 m ahead of the bit. The decision was to set the casing point at 1706 m MD, 4-5 m from the estimated top M. Coring results and open hole logging in the subsequent 8 ½-in hole section confirmed that top M was at 1711 m MD, 5 m from the casing point, which was precisely as estimated from Real-Time EM Look Ahead Technology. This technology also helped detect thin limestone stringer and differentiate it from the target carbonate formation. It prevented 9 ⅝-in casing to be set ~118 m shallower where the first limestone stringer was observed. This has avoided extra operating days in case of drilling problems due to long exposed shale in the subsequent 8 ½-in hole section. The potential cost savings were estimated at USD 1.35 million for an additional 6-in hole section. Following this success, the same technology will be used in the next planned exploration wells.

The strong domestic need for oil in China requires further exploration in unconventional reservoirs, such as volcanic and shale oil reservoirs. Sweet zone identification is one of the most critical missions in formation evaluation. The complex mineralogy and the low porosity in unconventional reservoirs result in little contrast of resistivities between oil-producing zones and water zones. Reducing uncertainties affecting the type of fluid in the reservoir and its potential movability is key to defining the optimal landing zones for future horizontal drains. In conventional reservoirs, nuclear magnetic resonance (NMR) logging based on cutoff analysis is the optimum choice for evaluating the porosity and pore geometry of hydrocarbon bearing reservoirs. However, the routine single-dimension T2 measurement is not sufficient for fluid typing in unconventional reservoirs because of the overlap of signals of various fluids in the T2 domain. This contribution presents case studies from a new generation NMR tool providing continuous 2D T1-T2 measurements. The T1-T2 measurements enable separation and quantification of different fluids in the pores. Fluid typing can be done by integration of other wireline logs such as spectroscopy and dielectric. Case studies are presented from volcanic and shale oil reservoirs in Xinjiang Oilfield of PetroChina. In the volcanic reservoir case, dedicated 2D data analytics technic is used to extract relevant signals from 2D NMR T1-T2 measurements. An integrated workflow combining wireline borehole electrical image, nuclear spectroscopy, dielectric dispersion and NMR T1-T2 gives an insight into the fluid composition in the pore system. Besides accurate measurements of lithology independent porosity and pore geometry from NMR, T1-T2 specific measurement of clay bound water volume and total water volume match well with the same measurements estimated from nuclear spectroscopy and dielectric dispersion logs. It lowers the uncertainties on fluid types in the volcanic reservoir where resistivities fail to differentiate wet zones and oil zones. In the shale oil reservoir case, a reservoir producibility index (RPI) derived from the integration of NMR T1-T2, wireline borehole electrical image, and nuclear spectroscopy is shown to be quite efficient in sweet zone identification and ranking. This paper discusses a novel application of a new generation NMR T1-T2 logging method in unconventional reservoirs, which helps the operator ascertain the potential of these reservoirs. The oil zones identified by the new method have promising oil productions. The workflow illustrated in the two case studies can be applied and extended to other unconventional plays in China.

One of the keys to successful and environmentally responsible well stimulation programs in coal seam gas development is to establish consistent procedures for the safeguarding, planning and executing activities across multiple wells. The aim of this paper is to show how a novel application of petrophysical program scripting can be used to make the stimulation process more efficient, consistent and compliant across assets with varying requirements. A macro embedded in petrophysical evaluation software applies a series of rules to rank coals by thickness, allocate a series of perforations and stimulation type based upon coal rank and spacing and then produces actionable treatment schedules which are seamlessly implemented in well stimulation operations at well sites. To do this, the macro grades all coals within the well by thickness based upon a cut-off on the density log, with the thickest coal being graded highest. The macro then identifies the top ranked coal and places perforations based on user defined logic, geological information from offset wells, permeability attributes of the target coal layer(s), depth and vertical separation between adjoining coal targets. Based on the stimulation type assigned, a stimulation schedule is generated that includes estimates of fluid volumes, proppant volumes, injection rates, proppant ramp type and stipulates flush conditions (over-flush or under-flush). Coals thicker than a maximum perforation size are perforated in an upper, middle and lower configuration. Most coals are thinner than the maximum allowable perforation interval and so the macro looks up and down the borehole to include thinner coals within a potential perforation window. The system then generates the stimulation schedule as described above. The macro continues to allocate perforations and stimulation schedules for each validated coal interval and sequentially tries to maximise the total target coal interval along the wellbore. Certain environmental constraints are included in the macro logic to maintain local and regional commitments. For example, coal zones in proximity of permeable non-coal layers i.e. interburden are automatically excluded from stimulation. Multiple advantages of this system have been realised including, a) effective QA/QC as outputs can be directly plotted against the well logs giving the user a quick and easy visual check b) actionable instructions that site based teams can execute including exact perforation depths and stimulation schedules c) provide realistic materials and costs estimates that ensure efficient planning and logistics, d) monitor and document any variations between allocated schedule versus actual execution, e) provide estimate of expected net coal connectivity at a well, development package and asset level which feeds into production and recovery forecasts, f) plan future optimisation studies or pilots and g) most importantly offers a consistent, efficient and compliant framework that can be applied across multiple assets, engineering teams and service providers. This paper focuses on capabilities and advantages of using a macro to automate stimulation design allocation for CSG multi-well (>100 wells) assets. Details of individual stimulation designs for Walloons Coal measures are mentioned in other publications ( Kirk-Burnnand et al., 2015 and Flottmann et al. 2018 ) and hence not covered here.

The coal-seam gas (CSG) industry has long been considered as a high volume, low cost market. As the industry has matured, the selective application of high-tier technologies has realized a step change in performance and real-time formation evaluation results. We investigated whether a high-tier LWD multi-function service could provide a suite of quantitative real-time measurements in several deviated wells. The key objective was to reduce the amount of non-productive rig time spent waiting for memory data in order to confirm the completion design. Significant savings in rig time could be realised if reliable, high-quality real-time data enabled the early identification of coal seams and permeable aquifers such that the swellable packer and slotted liner completion design could be completed without the need for final memory logs. The area of interest is characterized by thin Jurassic coal seams rather than thick Permian seams. It was critical to accurately identify thin coal beds in real-time whilst maintaining a high rate of penetration (ROP). Low-resolution data would result in poor completion design, underestimation of net coal reserves, and sub-optimal static models. Measuring coal thickness and properties can be difficult due to the fundamental differences between the formation evaluation measurements and their relative axial resolutions. The presence of thin coals can further complicate the interpretation. Another challenge was to optimize the real-time data transmission to prevent any limitation on the key directional drilling data parameters. Conventional LWD logs (gamma ray, nuclear, and resistivity measurements) provide formation evaluation information while drilling. The selection of a rotary steerable system (RSS) was critical as it ensured directional control and avoided any sliding intervals over key aquifers and coal zones, thereby ensuring optimal LWD acquisition. Advanced formation evaluation options of the LWD data also included using dual-pass resistivity inversions for Rt/Rxo to determine the invasion profile in a permeable aquifer zone above the main coal-producing reservoir. Having this information in real-time was critical in guiding well-specific competition decisions. Induction and laterolog-type resistivity tools were run on one well to quantify differences in the measurements and to determine the best resistivity acquisition tool for CSG wells drilled with saline muds in freshwater formations. The results showed that high-tier LWD technologies provide multiple benefits in CSG wells. The project was executed with all directional and logging objectives achieved. Quantitative real-time data was critical for completion decisions including ECP placement together with swellable packer and slotted liner designs. This resulted in significant cost savings which are important to major CSG developments operating within a low-cost operating model. LWD memory data provided a rich suite of additional measurements to complement the real-time data. Memory data was used for advanced reservoir analysis with industry-unique measurements.

Bulk permeability of coal is a critical parameter in coalbed methane (CBM) or coal seam gas (CSG) well completion designs and field development planning. The estimation of permeability can be made by well testing either during drilling or production; however, well tests are costly, time sensitive and resource-intensive. Therefore, field-wide estimates are often dependent on production data history-matching, which has a high degree of uncertainty. In this paper, we present a new attempt to apply machine learning approach to estimate coal permeability using drilling data. We first extract important parameters from well test analyses, which are obtained using a packer element testing (PET) tool from four wells in the Surat Basin, Australia. Then drilling data from the wells are processed and fed into different artificial neural networks (ANNs), which include multi-layer perceptrons (MLP), convolutional neural network (CNN), and recurrent neural network (RNN). Two types of models are constructed: regression model with permeability values, and classification model with permeability class intervals (i.e., low, medium, and high permeability values). The evaluation metrics include R 2 for regression models and confusion matrix for classification models. Results show that the drilling mud losses are generally higher in coal layers and lower in interburden formations. The predicted medium and high coal permeabilities from MLP and CNN are in good agreement with measured permeability values from PET data. For the classification task, the CNN achieved an overall accuracy of 99%. Thus, an improved coal permeability map with a higher resolution and less calibration against PET data can be developed quickly to aid production data history matching. The developed machine learning model demonstrated a potential to be applied to new wells to predict the coal permeability for the Surat Basin as well as other CSG appraisal projects. This model can allow more rapid optimisation of well spacing, improved downhole pump design, more targeted well stimulation, and overall project economics.

This paper presents a case study on usefulness of having geomechanical understanding to avoid drilling risks and minimize costs in a Drilling campaign, Offshore Peninsular Malaysia. Significant drilling issues related to wellbore stability were encountered in the four exploration wells drilled during previous campaigns. The development wells were planned to drill with high inclinations (up to 70 0 ), through weak coal layers and cross major fault. The drilling problems of the offset wells were critically analyzed to understand the mechanisms of failures. A geomechanical model was built using the offset well information. The well-calibrated stress model was then used for the wellbore stability modeling for the planned trajectories. The outcome of this study was used as key input for casing and mud design. With the help of the reccomendations based on this study, six highly inclined development wells were drilled through low pressure and narrow mud window intervals without operational problems. Reducing non-productive time (NPT) for the entire drilling campaign was one of the key focus for delivering the wells safely within schedule and budget. This paper documents the entire workflow and methodologies used for this entire study.

The first hydraulic-jet-fracturing multizone completion application was performed in an offshore high-permeability oil well located in the Bozhong oil field in Bohai Bay, China. A detailed case study is presented, highlighting operational challenges and lessons learned from the offshore multizone completion in the Bozhong field. Most offshore high-permeability oilwell completions in the Bozhong field employ tubing conveyed perforation (TCP) followed by frac-packing as multi-zone completions, which is practical in this field. Unlike conventional multizone frac-pack completions, to run perforation guns, the perforating must be completed first, followed by running isolation packers to complete the multizone frac-packing treatments. For hydraulic-jet-fracturing multizone completions, the hydraulic jetting tools are delivered to the target depth using drill pipe; following that, slurry fluid is pumped through the drill pipe to cut through the casing to create fluid flowing channels, which communicate with the pay zone formation. Lastly, the fracturing operation is completed by pumping both proppant slurry through the drill pipe and cleaning fluid through the annulus simultaneously, which creates dynamic hydraulic diversion as functions of isolation between zones. After completing one treatment zone, the tools are pulled to the next target depth, repeating the procedures, until the entire well is complete. After the fracturing treatment, the operator runs production tubing and other accessories, putting the well into production as usual. A detailed completion design and step-by-step operational procedures were prepared based on well data and work conditions to help ensure the effectiveness and safety of the offshore operation. Although some challenges were encountered during the operation, it was overall successfully performed, and significant performance improvement was achieved. After being in production for months, the candidate well has maintained a longer high-production-rate period than the offset wells completed using conventional multizone frac-pack completions. This hydraulic-jet-fracturing multizone completion has proven successful in the Bozhong oil field. The experiences and lessons learned can help benefit future multizone completion optimization for other similar offshore high-permeability oil wells.

The use of radioactive source porosity measurements is strictly prohibited in Bohai Bay, China. As an alternative, logging-while-drilling nuclear magnetic resonance (LWD-NMR) has been applied. In one block of the Bohai Bay field, it is a big challenge to identify and quantify hydrocarbon reservoir sections due to little resistivity contrast between reservoirs and water zones. LWD-NMR technology and the azimuthal resistivity tool is able to solve this challenge. The low-gradient LWD-NMR tool not only measured porosity also provide T 2 distributions, which can be used for fluid type characterization. The azimuthal resistivity tool has a deep azimuthal resistivity measurement that can identify nearby bed boundaries, up to 5 m from the borehole, while drilling. This information is available in real-time to the operator for decisions while drilling. The combination of the two measurements is capable of differentiating physical properties of the reservoir and providing information on fluid types. Thus, the operator can easily make decisions to optimize the wellbore placement and perform an accurate petrophysical evaluation of the reservoir. A pilot hole and a horizontal hole are presented in this paper to show the advantages of LWD-NMR and the azimuthal resistivity respectively. In the pilot hole, the LWD-NMR has been used for fluid typing which can give a clear petrophysical interpretation of the reservoir fluids. Because in this low-resistivity contrast reservoir, it is difficult to differentiate oil zones (10+ Ohmm) and water zones (9- Ohmm) from resistivity data. The light oil, however, shows a much slower NMR T 2 relaxation time than the water. Based on the identification of oil versus water by NMR in the pilot hole, three horizontal wells were successfully drilled in the oil zone. In one of them, LWD-NMR and azimuthal resistivity have been employed simultaneously for optimal wellbore placement by enabling to drill in the best part of the reservoir. The LWD-NMR measurements indicated reliably the presence of hydrocarbons and provided important reservoir properties. The azimuthal resistivity measurements identified the reservoir boundaries and the distance to them. Under complex reservoir conditions as encountered in Bohai Bay, azimuthal resistivity and LWD NMR prove to be an accurate and robust source-less measurement combination. LWD NMR can effectively replace the traditional density-neutron source measurements for porosity. More importantly, the combination with azimuthal resistivity provides the operator with additional critical information for optimal wellbore placement and strengthening the confidence in petrophysical interpretation results.

There was always the challenge to match Permeability estimated from logs to Permeability derived from well tests. The main reason for this is the difference in scale, both vertically in the borehole (net contributing sands) as well as radially out into the formation. The well test that takes into consideration many hours of fluid flow into the borehole was always deemed more representative than permeability derived from logs that measures a smaller area and volume. However, this perception should not relegate log-derived permeability to an insignificant parameter within dynamic models. When wells are stimulated prior to well test (e.g. under-balanced perforation or chemical stimulation for clean-up), it is expected that the permeability from the well test be enhanced as seen in Iago-2 and Gorgon-3 wells. This paper takes core data from wells in the Carnarvon Basin, create log relationships to predict permeability that match these core data, and compare these to wireline formation tester mobility and to well tests. The results are very promising, and the workflow proposed can be applied to any well in the basin. One of the objectives of this paper is to create a workflow that can be replicated easily and to use raw logs that are available across all wells, in order to reduce the uncertainty in the predicted permeability. The reservoir sands of the Mungaroo formation are easily recognised by the cross over in the neutron-density logs, in both gas zones and water zones. This is the criteria used by operators to obtain formation pressure tests (MDT/RFT) and this is the same criteria used in this paper to define reservoir sands. Only those core data acquired in reservoir sands are used as the "Learning" dataset to predict permeability. Several learning datasets were created, and these were blind tested on other wells that were not part of the learning dataset. The results of these predicted permeabilities were cross plotted against core permeability that have been over-burden corrected and depth shifted to wireline logs. Where the match is not satisfactory, new learning datasets are derived and this step of the workflow is repeated. At the end, there are four groups of learning datasets that are used as the final results. These four groups of datasets are associated with four sets of equations and these provides a very good match between the predicted log-derived permeabilities and core plug permeabilities. When compared to mobilities from formation pressure testers, the predicted permeabilities are a very good match. These were then compared to well test permeabilities showing an overall good match. This gives confidence that the predicted permeabilities from the four sets of equations are good and can be applied to any new well targeting the Mungaroo Formation in the Carnarvon Basin.

A state-of-the-art time-domain electromagnetic tool is presented that is capable of quantifying four barriers individually, and inspecting a fifth barrier qualitatively. The working physics and salient features of the tool and its underlying technology are described. The new tool uses time-domain electromagnetic (TEM) or pulsed eddy current (PEC) technology, which has set the benchmark for individual quantitative tubular corrosion evaluation in multi-annular well systems (multiple concentric tubulars) in recent years. Time-domain electromagnetic tools widely used in the industry are currently capable of quantifying the individual metal thickness/loss in up to three barriers. The new tool employs three highly sensitive sensors to provide high-resolution analysis of the inner barrier, while providing sufficient radial depth of investigation for up to five barriers. The above features and advantages of the new tool are supported by modeling and fixture test results. Additional modeling is shown to compare and contrast the resolution and radial depth of investigation of the three sensors. Case studies from actual wells are also presented that illustrate how three sensors enhance the performance of this technology. Corrosion evaluation of multi-barrier systems is a major component of well integrity management because it can provide timely and cost-effective information for planning well repairs if needed. The ability of the new tool to inspect more barriers is important because it gives the operator better information for more proactive well integrity management. The novelty of the tool is in its ability to exploit the information-rich wideband pulsed excitation using three sensors that enhance the sensitivity to multiple barriers.

A common operation performed in oilfields is that of plug and abandonment (P&A) whereby a well is permanently closed at the end of its economic life. The regulatory requirements for this operation may vary between countries, however, it is imperative to establish that there is no potential for uncontrolled fluid flow to surface and freshwater aquifers are hydraulically isolated in the wellbore. This entails an accurate assessment of casing and cement integrity including an unambiguous determination of the top of cement (TOC). Towards the end of the plugging operation, a cut is placed above TOC, and the casing is retrieved from the well. There are several challenges associated with cement evaluation in old wells. The well may have gas or gasified fluid in the wellbore, depleted formations making it difficult or impossible to fill the wellbore with liquid prior to cement evaluation logging, casing damage or open perforations may preclude application of pressure to differentiate free pipe from micro-annulus conditions and records on cement and operations history may be sparse. Drilling muds are often weighted using barite or other weighting materials. With an incomplete removal of mud, during well completion, these heavy materials sag, settle and solidify, behind casing, over the life of the well. An often-encountered consequence of solidified mud is to shift casing free-point to a depth well above TOC. Traditional cement evaluation tools find it difficult to identify this condition leading to unsuccessful casing cut and retrieval attempts, and associated time and cost overruns. A new cement logging technique uses electro-magnetic transducers and multiple wave modes to overcome operational and evaluation challenges met in P&A operations. We will present a case study, from Southeast Asia, where the operator was concerned about risks associated with solids sag, above cement, in a 60 years old well. The new service provided accurate cement evaluation across depleted reservoir sections and over intervals with micro-annulus condition. Top of cement was clearly differentiated from the top of solid mud behind casing. A free-point depth was selected and casing was cut and pulled in first attempt. Operator estimated an overall saving of two days in rig time.

The operator, rig contractor and services company formed a trilateral collaboration to plan the safe plug and abandonment of four onshore wells located in a densely populated region of Indonesia. These wells, located in scattered locations, posed a significant logistical challenge for project mobilization and moves between the wells. Well information was incomplete due to a change in asset ownership. Some of the challenges faced in these wells were: Well integrity issues resulting from the presence of H 2 S and CO 2 Sustained casing pressure Surface water safety Fluid losses Personnel safety and future well integrity was crucial to this operation. Consequently, plans were developed to conduct the operation safely and efficiently, as well as to provide solutions that mitigated well integrity challenges. The method adopted for this project was to approach this as an integrated project where the collaboration team was responsible for planning, executing, monitoring and closing out all segments of the project. Well information from the previous field operator was analyzed and a solution to safely plug and abandon these wells was created. Because inadequate well information posed a major challenge, the collaboration team planned multiple contingencies. An abandon-the well-on-paper (AWOP) workshop was organized to review and refine the execution plan. An intelligent coiled tubing system, which could be used for simultaneous logging and pumping operations, was selected as well as an efficient and environmentally friendly mechanical pipe cutter that did not use explosives or hazardous chemical substances for tubing severance operations. The sustained casing pressure challenges (in previously fully cemented/non sealing annuli) were addressed by using advanced milling technology for section milling. The early engagement plan enabled development of a project execution strategy that clearly outlined equipment mobilization schedules from various locations in Indonesia. Because of the collaborative projects structure, local personnel recruited for this project were quickly on boarded and integrated with the rest of the project team. This approach led to the safe and efficient execution of the plug-and-abandonment scope of work, with zero HS&E incidents and 167 perfect HS&E days during project execution. Extensive testing of cement mix water was introduced to this project. The testing improved the cement design and enabled accurate plan transition times that reduced waiting on cement. Based on lessons learnt from the first well, extensive logging operations were performed to determine the formation temperature and specific leak locations in the casing. These pre-cementing logging operations helped in collecting accurate well temperature and pressure information that aided the design of cement recipes for the barriers placed in these wells.

Production Enhancement (PE) opportunities in a 30 years-old Field D in Balingian province, offshore of Sarawak, Malaysia are dwindling. Behind casing opportunities (BCO) in relation to bypassed pay with good reservoir properties are either already perforated and produced or too costly and complex to be executed due to well issues. An in-house evaluation tool, Resolution Enhanced Modelling (REM), was developed by PETRONAS Petrophysics Department to evaluate and characterize thin beds or laminations. These Low-Resistivity-Low-Contrast (LRLC) sands are commonly bypassed as conventional logging tools cannot resolve their true parametric values and the apparent log responses across these zones appeared as shaly sand. By running REM across these intervals, the properties of the thin sands can be properly characterized, improving the net pay and economics of perforating and producing these reservoirs. In addition, a Rock Type (RT) based technique was used to evaluate some LRLC candidates in Field D. REM was run on LRLC sections in idle wells to evaluate their potential. To derisk and test the methodology, Well A3 with relatively more promising results was chosen as the first well to be perforated. Moreover, both strings of Well A3 were idle which makes it operationally easier to carry out the perforation job. From the initial analysis, the LRLC intervals in Well A3 could contribute to additional reserves of 0.3 MMstb with start rate of 300 bopd. The job required usage of barge assisted coiled tubing to pump cement and shut off existing high watercut zone and slickline to perforate through tubing. The actual job duration was prolonged from 30 days to 50 days due to monsoon season, driving the cost up to twice the planned amount. Post perforation, the initial oil rate was tested to be 500 bopd. After increasing the choke size, the well could flow at 800 bopd. Convinced by the success of Well A3, the same methodology was applied to Well C8 located at the north side of the field. Well C8 encountered operational difficulties such as lower than expected top of cement and perforation gun malfunction, resulting in only 54% of the proposed depth being perforated. Well C8 produced high gas, with initial well test rate of 10 bopd. Managing a brownfield where the easy oil is mostly exhausted can be challenging. Therefore, the team has to be more creative in unlocking the remaining oil and prolonging the life of a well. By using REM, the overlooked potentials hidden in LRLC sands can be accurately estimated, making the economics to perforate them more attractive to pursue.

Successful reservoir surveillance is a key component to effectively manage any field production strategy. For open hole extended reach horizontal wells, including some wells over 30,000 ft in length, the challenges to successfully deploy real-time logging tools are greatly magnified. This is further complicated by constraints in the completion where Electrical Submersible Pumps (ESP's) are installed. A comparative review of the latest technologies and methods available to overcome these challenges will be explored. The challenges are formidable and extensive; logging these extreme lengths in cased hole would be difficult enough, but are considerably exaggerated in the open-hole condition. The logging run in open hole must also contend with increased frictional forces, high dogleg severity, washouts and an increased well bore rugosity. The main challenges to achieve the logging objectives in open hole extended reach wells, are 2-fold, namely; To log the entire open hole section and reach the Total Depth (TD) of the well. To obtain high quality data from the logging tools, despite the adverse downhole environment. To achieve these 2 main objectives, a comprehensive approach is taken while designing the logging operation. The choices available to deploy the logging tools are mainly on electric-line cable with an electric powered tractor or on coil tubing with a hydraulically powered tractor. The most common type of log performed in these extended reach wells is a production log to measure multi-phase inflow contributions. To improve the success rate of the logs, a number of initiatives have been implemented, including deployment of custom designed coil tubing tractors and state of the art wireline tractors. The logging tools and job programs are adapted based on the results of simulations, accounting for many variables, including the completion, well type, deviation and target depth. The ability to successfully log these extended reach wells cannot be understated, reservoir simulations and management decisions can only as good as the quality of data available. Some of the advantages of drilling mega reach wells such as increased reservoir contact, reduced footprint and less wells drilled will be lost if adequate reservoir surveillance cannot be achieved. To meet the key objectives, creative solutions including designing and upgrading the best fit for purpose technologies are applied for the extended reach wells. These steps taken not only improve the overall logging performance, they can also result in cost savings by avoiding multiple unsuccessful logging runs.

Defining pressure dependent permeability (PDP) behaviour in coalbed methane (CBM) or coal seam gas (CSG) reservoirs using reservoir simulation is non-unique based on the uncertainty in coal properties and input parameters. A diagnostic fracture injection test (DFIT) can be used to investigate bulk permeability at a reservoir level and at lowered net effective stress conditions. As coal has minimal matrix porosity and under DFIT conditions cleat porosity is fluid saturated with reasonably definable total compressibility values, the DFIT data can provide insight into PDP parameters. At pressures above the fissure opening pressure, pressure dependent leak off (PDL) behaviour increases exponentially with increasing pressure. Many authors have noted that with decreasing pressure PDP declines exponentially with increasing net effective stress. Thus, PDP behaviour can be defined by PDL. In this paper, we show how combined analyses, using typically collected field data, can be used to better define and constrain the modelling of PDP. We illustrate this process based on a well case study that includes the following data: fracture fabric and porosity reasonably defined from image log and areal core studies; DFIT data acquired under initial saturation conditions; hydraulic fracturing data; and longer term production data. These analyses will be integrated and used to constrain the parameters required to obtain a rate and pressure history-match from the post-frac well production data. This workflow has application in other coal seam gas cases by identifying key variables where hydraulic fracturing performance has been unable to overcome limitations based on pressure or stress dependent behaviours and often accompanied by low reservoir permeability values. While this is purposely targeting areas where only typically collected field data is available, this workflow can include coal testing data for matrix swelling/shrinkage properties or other production data analysis techniques.

A clear description of the wettability of carbonate rocks poses numerous challenges due to its non-uniformity and uncertainty caused by complex pore systems and weak fluid/rock interactions. Aging in the crude oil and spontaneous brine imbibition of core samples in the laboratory constitute essential steps of wettability restoration, wettability measurement, and oil mobilization. Various aging durations are used to restore the carbonate wettability by researchers. The imbibed oil/water quantities in the Amott test are sometimes in the range of several percentages, and it is not clear if the fluids contact the whole core. This study investigates how the wettability evolves during again and how the imbibition develops in reservoir carbonate rocks using nuclear magnetic resonance imaging techniques. The carbonate core samples with typical multiple pore systems were first saturated with crude oil at different irreducible saturation by centrifuge and aged for different durations. Then they were immersed in deuterium oxide (D 2 O) with two ends open (TEO) at an elevated temperature for spontaneous imbibition. The aging and spontaneous imbibition processes were monitored by a 1D magnetic resonance imager either by a standard probe or a high temperature and high pressure core holder. A set of nuclear magnetic resonance measurements were conducted for any wettability alteration and oil/brine imbibition front propagations. NMR measurements during oil saturation and aging of three carbonate reservoir core samples indicate that the significant wettability change occurs after the oil flood while further aging continues to alter the wettability on a smaller scale. Low oil saturation has less of an effect on the wettability than high oil saturation. The brine imbibition fronts were found to develop from both ends or one end only, or there could be no apparent fronts. After the fronts propagate across the samples, a significant amount of brine continues to imbibe globally. The high permeability macro pore dominated samples appear to have significantly higher total brine imbibition than the low permeability micro pore dominated samples from current experimental results. Lower initial brine saturation impedes the imbibition with negligible effects on the final amount. Aging does not have appreciable effects on the brine imbibition for the samples studied. The direct observations of wettability evolution during aging and brine spatial propagation during brine imbibition by NMR under reservoir conditions provide novel information about carbonate wettability, which assists in better wettability characterization and enhanced oil mobilization by wettability alteration.

The presented reservoir in this paper is a tight carbonate reservoir with vertical and horizontal heterogeneous properties. In particular, the low clay content in this reservoir gives low gamma ray counts, making difficult the layer identification. In addition, the high-resistivity response of hydrocarbon-bearing pay-zones and of the tight layers make more difficult the identification of the reservoir sweet spots. Slim-hole magnetic resonance (MR) logging was deployed in wash-down mode for identifying reservoir sweet-spots for providing lithology-independent porosity and formation fluid characterization. The well placement over a deep elongated anticline with steep dips and the lowering of the production liner are challenging. Consequently, the field is being developed using horizontal wells that cut across multiple reservoir layers to maximize reservoir contact and drainage. MR was acquired with dual wait time enabled T2 polarization to differentiate between moveable water and hydrocarbons. After acquisition, the standard deliverables are partial porosities and permeability index. The porosity is divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). The effective porosity, the permeability index and the permeability-effective porosity ratio were used to evaluate the rock quality. The classification was based on the gradient of the permeability-effective porosity ratio, where a steeper gradient is interpreted as high flow zone, a gentle gradient as low flow zone and a flat gradient is considered as tight baffle zone. Based on the MR flow units and fluid types (CBW, BVI and BVM), the drilled interval was classified into six compartments of high flow, one compartment of low flow and five tight baffle zones. Accordingly, the perforation plan was optimized to fit the high flow units only. Comparing to the conventional log analysis, MR excluded approximately 700 ft of non-productive reservoirs, leading to more than 250,000 USD cost savings in perforation, drilling time and production optimization. The well was drilled with a distance-to-bed boundary tool; however, enormous potential exists to use this slim MR tool as a non-radioactive sourceless solution for geosteering through reservoir sweet spots while delivering wells that are more productive safely.

Today's exploration, production and operation in the oil and gas industry dealing with data in various types of format. Integrating these diverse types of data are difficult and some of the data might be scattered in the employee's personal computer. The initial concept of collaboration database management is to create comprehensive upstream database system in an integrated portal to handle upstream data information in a relevance format based on historical and up-to-date representation data in the company. The core of data visualization is mainly supported by map and web services that is connected to multi-database including Professional Petroleum Data Management (PPDM), geospatial, and lynx application. To distribute web and map services, a comprehensive script was created to transfer information within the web portal and optimize its functionality. There are some challenges of building an integrating platform of lynx and geographic information system. From the phase of development, dealing with data duplication, consolidate between data and application, and integrating web and map services are the main challenges of our methodology. To handle these issues, a primary key between technical data and database is defined to correlate a relation between database and application reading and deploying metadata from the source to the web portal. As the result, the collaboration data mangement was successfully developed and deployed into company system. Map, table, and report section are well established and optimized with functions that we built during the development. Both map and upstream data web services were linked to the web portal to open seismic and well section. Users now have a portal to find their data information and visualize it in the same window.

High-water-saturation ( S w ) bioturbated zones are generally bypassed due to the perception that those are non-oil-bearing, nonproductive zones. The major challenge in bioturbated pay zones is low resistivity, which leads to high S w calculation. The hydrocarbon could then be bypassed in the existing completion. The high S w also contributes to an inaccurate static model and stock tank oil originally in place (STOIIP) calculation. This study is to prove that bioturbated zones can add oil flow (as part of behind-casing opportunities from the current idle wells in many fields in Malaysia) and contribute meaningfully to the STOIIP. The objective of this paper is to use multifunction pulsed neutron service to identify and quantify the remaining oil saturation in bioturbated reservoirs. The examples shown are from a mature field located in offshore Sarawak. Pulsed neutron logging (PNL) is a well-established technology in casedhole reservoir monitoring and evaluation. However, the challenging environment with dual-tubing completions makes quantitative interpretation very difficult. The new generation slim pulsed neutron logging tool used in this study improves both sigma (∑) and carbon/oxygen (C/O) ratio. It also provides fast neutron cross section (FNXS), a new measurement very sensitive to formation gas and dry weight total organic carbon (DWTOC). More reliable answers help the subsurface team to select the perforation intervals confidently. The hydrocarbon zones in bioturbated reservoirs were clearly identified. The remaining oil saturation was computed from much improved C/O ratios and the independent DWTOC method. The positive production results confirmed that the measurements and interpretation are accurate and more robust.

Mahakam field was experiencing gas production decline in some offshore wells. Previous interventions done in the past indicated the high probability of scale and sand which had reduced the production flow path, it had also prevented perforation gun from reaching the target depth in order to perform additional perforation to increase well potential. Considering existing perforated reservoirs in the wells were still productive, Pertamina Hulu Mahakam (PHM) preferred to use well clean out method without invading/damaging open reservoirs. The additional cost of lost or deferred production was always unwanted. The deployment of traditional rig or coiled tubing unit to help restoring production came with considerable cost due to the equipment and personnel requirements. Consequently, PHM continually looked for new techniques to reduce this challenge. Milling on wireline, where applicable, was one solution since it could be performed in rig-less environment. The delivery of wireline deployed milling services had been provided by conveying a specially designed milling tool which had its own built in control, power and drive section. The bit design could be customized to make the tool fit for specific application. For a milling tool to operate properly on wireline, there were 2 physical principles that were needed to be dealt with; weight on bit (WOB) and anti-torque. To address this, wireline tractor was used. This system fit perfectly with the context of mature field; simple, cost-effective, safe and easy to handle.