Tunu is a mature giant gas field, located in swamp area of Mahakam delta. It covers an area of 75 km long and 15 km wide with enormous multi-layer sand-shale series deposited within a deltaic environment. The production commenced in 1990 and peaked in 1999 (1.5 Bcfd yearly average), with current production around 600 MMscfd, and nearly 1,200 wells drilled from 34 platforms.
As the field is entering into the late stage of its life and number of new wells being drilled is decreasing, the field potential is now quite dependent on the existing perforation portfolio. Owing to the significant number of wells, with multi-layer reservoirs encountered by each well, the perforation portfolio needs to be managed in an efficient and detailed manner.
An intensive well review has been performed, involving more than 9,000 reservoirs located in over 800 active wells. It commenced with an evaluation of perforation gain and its associated risks at reservoir level, which are then progressively summarized into higher levels; well, platform, and field. Perforation sequences are then defined for each well following a bottom-up perforation strategy while also adapting the risks of each reservoir. Ultimately, an organized reservoir chart is constructed where we can dynamically surveil the field perforation portfolio.
Results of this intensive well review have enabled the shift of production forecast methodology from statistical toward deterministic approach. In the new approach, for instance, perforation sequences and time interval between the sequences in each well are deterministically determined on a well by well basis according to the aforementioned reservoir chart. Compared to the previous methodology, this new approach yields a better representation of the actual operations.
Another area benefited by the results of the intensive well review is the optimization of well intervention planning. The identified workload is grouped together based on the remaining perforation portfolio of each platform while also respecting their location to define several well intervention clusters. Implementation of this clustering system optimizes perforation planning which reduces the time spent by perforation barges to travel from one platform to another, thus allowing more time for perforation.
This paper demonstrates successful application of parallel appraisal and development in G field, Niger. G field is a complicated stacked light oil reservoir with gas cap in its E2 major pool. After current operator's takeover in 2008, the government required realization of 10 KBOPD in this field within 3 years, leaving only 1 year for appraisal and development as field construction in this landlocked country at least takes 2 years. Whereas there was only 2D seismic and one well data (G-1) with RFT and testing, parallel appraisal and development strategy must be adopted and following 2 major challenges were identified: 1) Limited data and great uncertainties in gas-cap and well productivity; 2) development decision-making along with appraisal process.
Appraisal and development have been optimized by following approaches: 1) RFT and wireline data were fully studied to identify oil-gas-contact in E2 pool and indicate possible oil in E3 pool; 2) appraisal wells placement based on new 3D seismic; 3) identify key uncertain development parameters and combine into appraisal campaign targets to gradually reduce uncertainties.
Appraisal well G-2 confirmed the separation of block G-1 and G-2. The second appraisal well G-3 confirmed oil-gas-contact, encountered oil zone in lower E3 pool. The third appraisal well G-8 encountered oil zone in E2 and further firm up gas-cap area, laying firm foundation for subsequent development well placement.6 producers were placed out of gas cap and appraisal wells were transferred to development wells, all successfully commissioned in 2011, achieving desired production target.
Conclusions drawn from successful parallel appraisal and development application were:1) utilization of all data available contributed to correct appraisal decision-making; 2) Combining 3D and appraisal well findings help reduce geological uncertainties; 3) Identify and reduce key development uncertainties during appraisal speed up appraisal process. For complicated fields at appraisal stage, the methodology in this paper is of strong reference value.
Injection of water in waterflooding operations provides pressure support and displaces oil in the reservoir, thereby improving the recovery factor. A factor of significant importance in this process is mobility ratio; a higher mobility ratio allows for better displacement of oil by the injected water. For further increasing the volume of reservoir swept, gelling agents are used to improve the mobility ratio of injected water. It is imperative to identify the right type and amount of viscosity reducer to be used since shear stress and high temperatures cause polymer degradation, due to which polymer macromolecules may be forced into narrow channels.
Performance of xanthan and synthetic polymers in a polymer injection process were compared. The model is assumption is that reduced gel kinetics forms a microgel without redox catalysis. For modeling purposes, a commercial reservoir simulator coupled with an optimization tool was used. The reservoir was modelled having 6 layers for injection, where first 4 layers have high horizontal permeabilities and the bottom 2 layers have a high permeability streak. For the first 450 days, injection water was continuously pumpedinto all layers andin the next 150 daysgel systems were injected only into the bottom 2 layers followed by which water was continuously injected for a period of 4 years. The optimization tool was used for sensitivity analysis investigation of variables to reduce variable uncertainty.
Per modelling results, gel penetrated deep in reservoir but in bottom layers there was blocking. In terms of viscosity effects, the relative benefits of biopolymers and xanthan polymer were highlighted in the sensitivity analysis. Also, this investigation indicated merits of synthetic PAM in terms of resistance factor, insitu gelation treatments and their crossflow dependence. Retention of polymer-gel and their adsorption were shown to be dependent on permeability.
In this study, for comparative purposes, different viscosity reduction treatments were modelled in the same model reservoir to highlight their relative advantages. Also, investigation of control variables through sensitivity analysis outlined the significance of each towards displacement efficiency. Keeping in mind the wide spectrum of areas around the globe where gel solutions can be applied, this study highlights factors that are critical to optimal reservoir management.
As the industry is facing continued low oil price and exploration targets deeper overpressured reservoirs, proper well planning is the key to lowering the cost of drilling. Pore pressure prediction is an important part of an asset team's planning process from assessing the seal integrity to delivering the pressure profiles to the drilling engineer. A precise prediction requires a multidisciplinary approach to address the challenges and uncertainties which in turn needs to be transferred to the drilling engineer while designing the well. This paper focuses on different aspects to be considered while planning and preparing a viable pore pressure analysis which has resulted in successful drilling of a wild cat HPHT exploration well in Offshore Sarawak, Malaysia. A predrill pore pressure prediction study was initiated involving three offset wells in Central Luconia Province Offshore Sarawak. Firstly, the uncertainties in prediction models arise from the quality and relevance of offset well control. In the study area, the two offset wells penetrated thick carbonate sequence and one offset well encountered thick sand-shale sequence with carbonate stringers. The variation in lithologies has to be considered while selecting the relevant offset well. Secondly, understanding the drilling challenges in offset wells related to pore pressure is key to design the planned well. All the offset wells drilled encountered significant challenges in terms of pore pressure. Similar drilling challenges were expected at the proposed location. However, the offset wells didn't penetrate the deeper cycles and as such there were no calibration in deeper undrilled section at the proposed location. The third aspect is the complexity of the geological and structural conditions around the well. The proposed well was planned to be drilled in a structure which was formed on the footwall block for the shallow targets and crossing the fault to hanging wall block to hit the main target in deeper cycles. The fourth one deals with overpressure generation mechanism and prediction methodologies. A conventional workflow to plan a wild cat exploration well makes a precise prediction almost impossible until the overpressure generation mechanism is well understood in the study area. Such analysis were carried out in offset wells to carry a fit for purpose prediction at the proposed location. The fifth aspect covers the seismic velocities in terms of quality and calibration. A very coarse 2D seismic velocities were available with very poor quality of seismic reflections along the proposed well path. The errors that are inherently present in such velocities from different sources has to be considered for determining the quality of the seismic based pore pressure calibration. Considering all the above aspects and the associated uncertainties, a fit for purpose pore pressure model was adopted. The paper explains how all the challenges were addressed to reduce the uncertainty and a three case scenario for pore pressure was proposed for well design. Based on postdrill analysis, the actual pore pressure was within the uncertainty model which helped to make decisions on well design in realtime.
Chen, Tianyu (The University of Queensland) | Hamilton, Stephanie (The University of Queensland) | Rodrigues, Sandra (The University of Queensland) | Golding, Suzanne D. (The University of Queensland) | Rudolph, Victor (The University of Queensland)
This experimental study aims to characterize the bioavailability of six Surat Basin Walloon coals to exogenous methanogenic consortia, and the possible compositional and environmental factors that control bioavailability. Finely crushed coal cores samples were inoculated with digested sludge culture sourced from domestic wastewater treatment plants in biomethane potential bottles (BMP bottles) maintained at mesophilic temperature. Degradation of coal compounds was demonstrated via GC-MS characterization of methanol and dichloromethane (DCM) extracts of coals, as well as analysis of volatile fatty acids and alcohols and total dissolved organic carbon (TOC) in water eluents of coals conducted before and after biodegradation. The resulting methane yields ranged from 14 to 33 μmol/g, with an average of 21 μmol/g (0.515 m3/t) achieved within 30 days. Organic solvent-extractable materials accounted for 3.8 to 12% of coal weight. Aliphatic compounds, primarily medium-long-chain
Liu, H. (Research Institute of Petroleum Exploration and Development, PetroChina) | Meng, S. (Research Institute of Petroleum Exploration and Development, PetroChina) | Zhao, Z. (Research Institute of Petroleum Exploration and Development, PetroChina) | Yan, J. (Research Institute of Petroleum Exploration and Development, PetroChina) | Yao, Z. (Research Institute of Petroleum Exploration and Development, PetroChina)
Over-developed oilfields in East China have gone through suffering situations induced by high cost in recent years. The trend of resource deterioration is irreversible and the deterioration leads to the increasing difficulties in oil and gas exploration and development. The rate of return-on-investment continually decreases resulting from over-rapidly increasing properties, and ever-rising facility depreciation and damage. The space for increasing income and seeking profit is further narrowed by low oil price. These oilfields now move into the period that has huge obstacles to increase profit, confronted with more difficulties in obtaining economic reserves and profitable production. Now the development in over-developed oilfields has stepped into double-high phase, meaning that to avoid ineffective or poorly effective measures and control the fundamental indices like the rise of watercut, natural decline, and so on play the key role in improving development profit. It is necessary to accelerate the build-up of production capacity and enhance reserve, production, and the rate of return-on-investment by actively reforming techniques for the formation of a series of new ones on enhancing oil recovery, as well as advancing the four-unified-into-one management mode of merging production and management, investment and cost, reserve increase and production build-up, and research and production. The concept of focusing on reserve and production must be further switched, meanwhile profit must be realized in all the ingredients of exploration and development during their whole processes, and efficiencies must be maximized. The burden of production and management is relieved, and the focus is switched to profit in an overall and complete way by further recognizing that investment today is tomorrow's cost and strictly controlling property scale to prevent its excessive increase.
In Te Giac Trang oil field, wells are completed with monobore design and with thru-tubing perforation carried out offline following the well completion phase. Producers in the field are perforated with underbalanced conditions through gas-lift application, which has resulted in relatively low-skin completions. In 2014 the first water injector was drilled in the field, with the same completion design applied as for the producers, however with no gas lift mandrels and surface gas lift line installed for cost saving. As a result, perforation of the injector was carried out without underbalanced conditions. The well started injection in November 2014 at 4k bwpd, with the bottom-hole injection pressure (BHIP) kept below the formation fracture pressure (FFP). Injection performance was below expectation, therefore in November 2015 re-/extended-perforation of key sand layers was carried out in order to increase the injection rate. Well injectivity however significantly reduced immediately following the re-/extended-perforation.
Pressure fall-off (PFO) tests were carried out on the injector, indicating significant near-wellbore damage following the re-perforation. Skin factor increased from +14 before the re-/extended-perforation to +50 afterwards. Impairment of the well injectivity was expected to be due to debris plugging the perforation tunnels. After thorough review of the options for remedial treatment, it was proposed to hydraulically fracture the formation using the existing water injection system. The objective of this treatment was to create and keep fractures open over a period of time, so that debris in the perforation tunnels could be pushed far away into the formation.
The treatment was carried out in February 2016, during which the water injection rate was increased to 12k bwpd, with BHIP significantly higher than FFP, and maintained at this over 3 days. PFO testing following the treatment indicated successful damage removal, with skin factor reduced to + 10. Subsequent well injection rate has been stable at 8k bwpd, with BHIP lower than FFP.
This paper describes the process of injection well performance evaluation, including PFO testing, acquiring reliable FFP, and application of remedial treatment through proppant-free hydraulic fracturing. The paper also covers the lessons learned on the design phase of injection well completion, on perforating and on the capacity of the water injection facility.
Rubianto, Irwan (Schlumberger) | Prasetia, Andi Eka (Schlumberger) | Detrizio, Pasquale (Schlumberger) | Charnvit, Kerati (Schlumberger) | Srisai, Wanchana (Schlumberger) | Follett, Meth (PTTEP) | Dejdamrongpreecha, Warapong (PTTEP) | Kudisri, Rapee (PTTEP) | Meghnani, Manoj (PTTEP) | Loux, Fabrice (PTTEP) | Phonpuntin, Visarut (PTTEP) | Eawprasert, Somphop (PTTEP)
Drilling narrow window wells conventionally have been well known to cause major wellbore issues to the Operator in the Gulf of Thailand. Therefore, managed pressure drilling (MPD) has been deployed since several years ago to mitigate the drilling problems. To ensure safety and optimize drilling time, it is necessary to identify the actual pore pressure while drilling wells with narrow marginin order to eliminate kick, ballooning and loss events.
The use of automated MPD system to precisely control bottomhole pressure (BHP) during connections combined withthe evaluation of bottom up gas trend while drilling enabled the pore pressure to be predicted accurately in almost real-time condition without the need to stop drilling in the Gulf of Thailand. Thus, the narrow window wells were drilled faster with MPD, which was beneficial for the Operator in the area where the fast factory drilling was necessary to make wells more economical. Furthermore, the use of this new method in effectively determining the actualpore pressure provided solutions to the Operator in mitigating wellbore issues at the same time improving drilling timeafter several years of MPD technology implementations. The estimated pore pressure results acquired with the new methodon several narrow window wells were even comparable to the actual wireline logging measurement results.
The objective of this paper is to introduce an effective and efficient method in determining pore pressure (PP) while drilling challenging wells with tight reservoir characteristic by utilizing MPD technology in the Gulf of Thailand. In addition, this paper also describes the drilling strategy, detail procedure and lesson learnedin verifying pore pressure with the new method.
We often face a higher level of difficulty when using conventional methods to drill through a formation with a narrow pressure window. Even slight changes to bottom hole pressure can lead to unwanted non-productive time (NPT) in the process of securing the well, such as handling a loss and/or kick in the wellbore, or even at times, an underground blowout.
Maintaining Constant Bottom Hole Pressure (CBHP) is one of Weatherford's Managed Pressure Drilling (MPD) technologies used to drill safely by keeping the well overbalanced yet below fracture gradient. This is done by applying Surface Back Pressure (SBP) through the use of a Rotating Control Device (RCD) and an Automated MPD Choke Manifold. CBHP applies precise surface back pressure into the annulus by means of automated MPD system to maintain the annulus pressure when circulating and static. CBHP is achieved during pipe connection when the drill string injection is turned off.
In the previously drilled well, the 0.5ppg pressure window caused an underground blowout while in the thief zone. The Synthetic Oil-Based Mud (SOBM) used in this well was designed to be statically under-balanced during pipe connection to keep ECD within the 220psi window while dynamic and static. The slip joint packer - the weakest link in the annulus system - restricted the MPD SBP to maximum of 350 psi after considering the margin of error. Due to high wellbore friction pressure, the Pressure-While-Drilling (PWD) signal was intentionally turned off 60 meters before Total Depth (TD) was called by reducing the pump speed from 430gpm to 300gpm.
MPD CBHP technique was successfully applied to drill the well until target depth was achieved exceeding the poor performance in the previously drilled well where target depth was not achieved and the well was abandoned due to underground blowout.
This paper describes achieving CBHP with Managed Pressure Drilling technique and the use of an automated system which enables "walk-the-line" between pore and fracture pressure gradient. As a result, the exploration well that was considered "undrillable" with conventional drilling technique in East Kalimantan area was successfully drilled to TD. The ability to precisely control the annulus pressure with statically underbalanced mud is one of distinct advantage of MPD which allow operators to reach planned target depth and retrieve subsurface information through logging operations.
A recent corrosion inhibitor recommendation for a low water cut gas condensate line was conducted by the use of weight loss measurements aided by the use of white light interferometry. Weight loss was studied using a standard rotating cage methodology. To assess localized attack on the coupons both as pitting and preferential weld corrosion (PWC), white light interferometry was utilized and the 3D scans that were produced were then used to assess both tendency for pitting corrosion as well as the depth of attack across the weldment regions.
Machined coupons from the pipeline material were provided by the operator to a set geometry to be used in a rotating cage apparatus. After preparation for corrosion testing, the coupons were prescanned then exposed to both inhibited and chemical-free synthetic fluids for periods of 120 and 500 hours. The tested coupons were then cleaned of corrosion products and rescanned using interferometry to assess any corrosion that had occurred.
From initial pre-test coupon geometries, the average weight loss results, and the depth of attack, individual corrosion rates for the weldment regions were calculated to assess the PWC in a complementary manner to using electrochemical techniques for determination of PWC. In addition to corrosion rate data, 3D profiling allowed visual assessment of preferential weld attack that is not possible using segmented weld electrodes, where individual electrodes are isolated and material lost due to the machining process. Evidence of localized corrosion in the form of pitting was captured across the weight loss coupon during the scanning process.
The technique allows for the following: Examination of whole weld sections with no material wastage between metallurgical zones during coupon machining Collection of supplementarydata to compare to electrochemical testing of welds Providing greater power for spatial assessment of PWC from 3 dimensional interferometry images
Examination of whole weld sections with no material wastage between metallurgical zones during coupon machining
Collection of supplementarydata to compare to electrochemical testing of welds
Providing greater power for spatial assessment of PWC from 3 dimensional interferometry images
This paper discusses the white light interferometry technique and results in detail, as well as demonstrating the pros and cons to utilizing non-destructive measurements, when compared to existing methodologies, for assessing localized corrosion.