|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Dalgit Singh, Harpreet Kaur (Weatherford Asia Pacific) | Ta Quoc, Bao (Weatherford Asia Pacific) | Chai Yong, Tan (Weatherford Asia Pacific) | Khanh, Do Van (PV Drilling) | Cuong, Nguyen Xuan (PV Drilling) | Tung, Hoang Thanh (PV Drilling) | Nam, Truong Hoai (Bien Dong POC) | Hai, Ngo Huu (Bien Dong POC) | Tuan, Dang Anh (Bien Dong POC) | Bao, Trinh Ngoc (Bien Dong POC) | Hung, Tran Nam (Bien Dong POC) | Cuong, Nguyen Pham Huy (Bien Dong POC)
High-pressure, high-temperature (HP/HT) environments often present kick and losses scenarios. Bien Dong POC Well-1 serves as an example of such scenarios with a very narrow-pressure operating window. Operational pressure challenges prohibited achieving the objectives.
While drilling the Bien Dong Well-1, the well encountered ballooning issues, high pore pressures, and a narrow window. As part of remedial actions when drilling Bien Dong Well-2 & Well-3, the Bien Dong POC drilling team decided to deploy MPD technology with constant bottomhole pressure and early kick-loss detection capabilities.
By applying MPD techniques, the team drilled the 12-1/4-in. hole section with the lowest possible mud weight to accommodate the narrow drilling window. Drilling the well sections to total depth (TD) took only 10 days in Well-2 and 14 days in Well-3. MPD also allowed stripping out of the hole with surface backpressure (SBP) instead of pumping out of the hole to minimize swab once in shoe, which reduced trips for considerable rig-time savings.
The wells were drilled using MPD technology on a semisubmersible tender-assisted rig. A comprehensive rig survey was conducted during the planning phase of rig construction. The survey outlined the permanent installation of the MPD system, including an automated MPD choke manifold and docking-station rotating control device (RCD). The MPD equipment was integrated into the rig on a flexible plug-and-play basis to enable easy rig up and rig down. The integration also enabled moving the equipment between wells when the rig skids and during the MPD operation. The success of MPD operations came through cooperation with team members, experience from lessons learned, and excellence in rig crew performance on well after well.
This paper will discuss how MPD technology led to campaign improvements and cost savings throughout Bien Dong Well-2 and Well-3.
Andersen, Pål Østebø (Dept of Energy Resources, University of Stavanger and The National IOR Centre of Norway, University of Stavanger) | Berawala, Dhruvit Satishchandra (Dept of Energy and Petroleum Technology, University of Stavanger and The National IOR Centre of Norway, University of Stavanger)
Chemically reactive flow is of significant importance for EOR due to possible wettability alteration (low salinity and smart water brines), scaling and chemically enhanced compaction, which all can affect hydrocarbon transportation. In particular, chalks (Ekofisk, Valhall) are highly sensitive to the composition of the injected brine (typically modified seawater) as demonstrated on lab and field scale. We present numerical and analytical solutions to interpret the link between geochemical alterations and creep compaction in chalk cores.
A 1D core scale model is proposed for interpreting geochemical compaction during reactive brine injection into chalk cores loaded uniaxially in creep state (compaction under constant applied effective stresses). An analytical solution is derived to describe the steady state ion and dissolution rate distributions. An analytical model for creep compaction is proposed based on the applied affective stress and the rocks ability to carry that stress as function of porosity. The two models are coupled as follows: The compaction rate is assumed enhanced by the dissolution rate. Further, the solid volume changes by mineral dissolution and precipitation, also affecting the compaction rate. Brine-dependent and non-uniform compaction is therefore built into the model via the dissolution rate distribution.
The model is validated against data from ~ 25 core samples where simple Mg-Ca-Na-Cl brines were injected at Ekofisk reservoir conditions (130 °C), in particular experimentally measured effluent concentrations, distributions in mineralogy after flooding and creep compaction behavior. The model captures the effect of varying key parameters such as brine composition, injection rate and initial porosity and can predict ionic and mineralogical profiles along the core, axial and radial deformation profiles locally and with time. This model is a highly useful tool for interpreting experimental data, predicting in-situ mineralogical distributions where measurements have not been made, and for predicting compaction behavior at changes in brine composition, injection rate or effective stress.
The model is intended for giving a prediction of qualitative and quantitative trends during flooding-compaction tests in chalks. The model and its methodology are translatable to other systems but is validated for lab measurements on chalk samples. Current modeling approaches do not consider the complex interplay between brine and rock compositions, reaction and compaction. This work aims to contribute to the current understanding of this topic.
Reservoir connectivity over production timescales is a key uncertainty impacting estimated ultimate recover (EUR) per well, and ultimately the economics of a development, but is difficult to address without production data (particularly where the reservoir is poorly defined by seismic). While appraisal well tests can be designed to help predict the performance of future development wells, high rig costs in deepwater means the test duration is often insufficient to investigate the volume that would be accessed under production conditions. Recoverable resources from a recent deepwater gas discovery were dependent on demonstrating significant reservoir connectivity and net reservoir volume; however, this was complicated by a lower delta plain interval that was dominated by sub-seismic reservoir elements.
This paper describes the acquisition and interpretation of long-term pressure build-up data in a plugged and abandoned deepwater appraisal well. To accomplish the test objectives at an acceptable cost, we turned to a novel combination of well testing, wireless gauge technology and material balance techniques to allow the collection and interpretation of reservoir pressure data over a planned period of 6 to 15 months following the well test. The final build-up duration was 428 days (14 months).
Three interpretation methods of increasing complexity were used to provide insights into the reservoir. Firstly, material balance was used to produce an estimate of the minimum connected reservoir volume. The advantage of material balance is that it requires very few input assumptions and produces a high confidence result. Secondly, we used analytical models in commercial pressure transient analysis software to investigate near wellbore properties and distances to boundaries. Finally, we used finite difference simulation models to investigate reservoir properties and heterogeneity throughout the entire tested volume. With increasing model complexity came additional insights into the reservoir properties and architecture but reduced solution uniqueness.
A key complication for the interpretation of the recorded pressure data was the potential for gauge drift to occur – this was incorporated into the uncertainty range used in all three interpretation methods. The observed relative performance for the various gauges used during the well test is also reported in this paper.
Commencement of initial field production is a unique opportunity to acquire reservoir surveillance information that can inform future reservoir performance. When a field is perturbed from original conditions with first production, there is potential for reservoir property uncertainty reduction by observing pressure measurements at non-producing wells with downhole pressure gauges and comparing the observed signal to a range of simulation model results.
The Wheatstone field, located offshore northwest Australia, has recently commenced production start-up to supply gas to the Wheatstone LNG facility. The operational guidelines required each development well to commence with a single well cleanup flow to the Wheatstone platform. The initial single well cleanup flows of the Wheatstone field allowed scope for the selection of a well flow sequence with observation at non-producing wells.
The recommended sequence of initial cleanup flows was designed with a focus on reducing reservoir uncertainties via the use of Ensemble Variance Analysis (EVA). EVA is a statistical correlation technique which compares the co-variance between two sets of output data with the same set of inputs. For the Wheatstone field well cleanup flow sequence selection, the EVA workflow compared the full field Design of Experiments (DoE) study of field depletion and a series of short early production reservoir simulation DoE studies of the gas field. The co-variance between the two DoE studies was evaluated. The objective of the EVA approach was to determine the startup sequence that would allow for the best opportunity for subsurface uncertainty reduction. This objective was met by ranking multiple cleanup flow sequence scenarios. The key factors considered for sequence selection ranking were the impact on business objectives such as future drilling campaign timing and location of infill wells, as well as insights on reservoir connectivity, gas initially in place and permeability.
The recommended sequence of well cleanup flows uses super-positioning of pressure signal to boost response at observation wells, which improves measurement resolvability. The selected sequence preserves key observation wells for each manifold and reservoir section for as long as possible before those wells were required to be flowed to meet operational requirements. Operational constraints and variations of the startup plan were considered as part of the evaluation.
Recent laboratory studies have shown fines migration induced decrease in rock permeability during CO2 injection. Fines migration is a pore scale phenomenon, yet previous laboratory studies did not conduct comprehensive pore scale characterization. This study utilizes integrated pore scale characterization techniques to study the phenomenon.
We present CO2 injection experiments performed on two Berea sandstone samples. The core samples are characterized using nitrogen permeability, X-ray micro-computed tomography (micro-CT), Scanning Electronic Microscopy with Energy Dispersive X-ray Spectroscopy (SEM-EDS) and Itrax X-ray Fluoresence (XRF) scanning. The core samples were flooded with freshwater, then CO2-saturated water, and finally water-saturated supercritical CO2 (scCO2). To calculate permeability, the pressure difference across the core samples was monitored during these fluid injections. The produced water samples were analysed using Inductively Coupled Plasma-Optical Emission Spectrometry (ICPOES). After the flooding experiment, nitrogen permeability, micro-CT, SEM-EDS and Itrax-XRF scanning was repeated to characterize pore scale damage. Micro-CT image based computations were run to estimate permeability decrease along the core sample length after injection.
Results show dissolution of dolomite and other high density minerals. Mineral dissolution dislodges fines particles which migrate during scCO2 injection. Berea 1 and Berea 2 showed respectively 29% and 13% increase in permeability during CO2-saturated water injection. But after water-saturated scCO2 injection, both Berea 1 and Berea 2 showed 60% decrease in permeability. The permeability damage of the sample can be explained by fines migration and subsequent blockage. SEM-EDS images also show some examples of pore blockage.
Cui, Weixiang (Petrochina Research Institute of Petroleum Exploration and Development) | Zou, Honglan (Petrochina Research Institute of Petroleum Exploration and Development) | Wang, Chunpeng (Petrochina Research Institute of Petroleum Exploration and Development) | Yang, Jiang (Xi'an Shiyou University) | Yan, Jun (Petrochina Research Institute of Petroleum Exploration and Development)
This paper studied a new fracturing fluid based on a supramolecular complex between associative polymer and viscoelastic surfactant (VES). The combination of VES and associative polymer synergistically enhances the viscosity several times more than that of the individual components alone. The fluid system was optimized by experimental design. The microstructure of wormlike micelle and complex formation was verified by electron microscopy. The proppant transport test in a large-scale fracture simulator showed good proppant suspension ability. After fracturing, the nano- surfactant molecule in the liquid have a high surface energy, which can play a good oil displacement effect in the crack.
The fluid has 50% lower formation damage than that of conventional guar. The fluid was prepared with less additives and formed gel instantly, which can be mixed on the fly in the field. The gel can be completely broken with almost no residue. By flooding and [
Supramolecular fracturing fluid provides a new fracturing system with less formation damage to fracturing operation. This paper will be beneficial to all engineers and technologists who are currently working at tight gas stimulation applications.
Abdulhadi, Muhammad (Halliburton Bayan Petroleum) | Kueh, Pei Tze (Halliburton Bayan Petroleum) | Zamanuri, Aiman (Halliburton Bayan Petroleum) | Thang, Wai Cheong (Halliburton Bayan Petroleum) | Chin, Hon Voon (Halliburton Bayan Petroleum) | Jacobs, Steve (Halliburton Bayan Petroleum) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Zaini, Ahmad Hafizi Ahmad (PETRONAS Carigali Sdn. Bhd.) | Jamel, Delwistiel (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Munandai, Hasim (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
In the recent low oil price environment, a cost-effective solution was proposed to use through tubing bridge plugs to perform water-shut-off (WSO) in an offshore field. The solution consisted of using slickline to set a plug with a high expansion ratio followed by a cement dump. After three WSO jobs in different wells, the method has successfully proven itself. Watercut was reduced from 100% to 0% with a minimal cost of only USD100,000.
The through tubing bridge plug used is capable of passing through 2-7/8-in. tubing and expanding into 9-5/8-in. casing. After running a Gamma-Ray log, the plug was set across the perforation interval to give the anchor contact with a rough casing surface. The top of the plug, however, was above the perforation interval and became the base for cement. Cement was then continuously dumped on top using a slickline dump bailer in a static condition until the designed cement height was reached. Static conditions ensured no movement of cement during operation. The plug differential pressure limit is directly proportional to the cement height.
The first WSO job was a complete success with watercut reduced from 100% to 0%. The second job however, was partially successful as the cement dump was not completed due to unexpected appearance of a hold-up-depth (HUD). The HUD was created by leftover cement which had accumulated at the end of the tubing. Despite the setbacks, the end result was successful in reducing water production from 1000 bwpd to 200 bwpd. The third job faced a completely different problem. The original plug fell off deeper into the well after it was set. To rectify the situation, a second plug was set at the target interval. Despite the successful execution, there was no change in watercut after the well was brought back online. Since the same method was proposed for another upcoming well, Memory-Production log (MPLT) coupled with Temperature-Noise log was performed to assess the effectiveness of the WSO. The log results confirmed that the WSO was successful and the post job water production was caused by channeling behind the casing. The results so far concluded that the through tubing bridge plug WSO method was both reliable and cost-effective. It is exceptionally suitable for zones located at the bottom of a well and can be deployed using slickline.
The paper provides valuable insight to a WSO solution which should be a first-choice option due to its relatively inexpensive cost and high reliability. The solution has proven to provide tremendous cost saving for production enhancement activity.
This paper describes a rigless and cost-effective field implementation of conformance polymer sealant (CPS) and particulate-CPS (PCPS) systems used successfully in high-permeability and low-pressure reservoirs for zonal isolation intervention. The CPS system is an organically crosslinked polymer that is thermally activated to effectively seal the targeted interval. The PCPS system combines the CPS system with particulates that provide leakoff control to help ensure shallow matrix penetration of the sealant. The traditional method for zonal isolation consists of rig intervention for cement squeeze, which can be time-consuming and expensive.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Hilgedick, Steven A. (Missouri University of Science and Technology) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids) | Alsaba, Mortadha T. (Australian College of Kuwait)
It is recognized that there is no single solution to lost circulation, and most treatment and trial-and-error. However, the screening guide presents a high-level ‘go to’ document with coherent guidelines, which engineers can utilize in making decisions regarding lost circulation treatments in major oil fields. The aim of this work is to describe how mud engineers can use the decision tree analysis (DTA) to evaluate and select the best treatments path for mitigating mud losses.
Lost circulation events of Southern Iraq oil fields were statistically analyzed to determine treatment effectiveness. Also, the cost of each treatment, as well as the NPT that is associated with the treatment, is considered in this study. Data from over 1000 wells were gathered from various sources and reports; the
treatments were classified by scenario -partial, severe, and complete losses - as well as cost, efficiency, and formation types. This paper is developed based on probabilities, expected monetary value (EMV), and decision tree analysis (DTA) to recommend the best-lost circulation treatments path for each type of losses.
Traditionally, lost circulation in Southern Iraq area has been treated in a multitude of ways without consistent methodology. This analysis identifies and ranks the most effective treatments to create a "best" method/product recommendation and a flowchart suggesting additional measures in treating losses to optimize success and reduce overall cost and NPT. This paper presents the best treatment for each scenario - partial loss, severe losses and complete losses - both for product selection and engineering.
This paper utilizes probability and economics in the decision-making process. This is the first study that considers a detailed probability and cost to treat the lost circulation problem. Thousands of treatment scenarios for each type of losses are conducted, and the EMVs for all scenarios are calculated. For each type of losses, the lowest EMV treatment strategy- that is practically applicable in the field and makes sense- is selected to be used to treat each type of losses to minimize NPT and cost. If the losses didn't stop after utilizing the proposed treatment strategies, it is recommended to use liner hanger to isolate the losses zone and then continue drilling.
One challenge in drilling wells in Southern Iraq oil fields is the inconsistency of approaches to the lost circulation problem. Therefore, the result of this data analysis provides a path forward for Southern Iraq area lost circulation events and suggests probable methods that can be used in similar formations globally. Additionally, the methodology can be adapted to studying other types of formations and drilling challenges have the same geological properties in any major oil field.
Heu, Tieng Soon (Sarawak Shell Berhad) | Wee, Anson (Sarawak Shell Berhad) | Combe, Caroline (Sarawak Shell Berhad) | Mohd-Radzi, Razif (Sarawak Shell Berhad) | Zhang, Ting-Ting (Sarawak Shell Berhad)
Conventional'textbook' primary cement job execution has always been associated with the combination of bumping top wiper plug, successful casing pressure test and/or no losses during the job. These criteria have been referenced by the general industry as positive indications and conveniently adopted as qualification for a successful cement job without considering other key parameters that contributes to proper cement isolation behind casing. In a deepwater development campaign offshore Malaysia, cement isolation behind the 9-5/8" production casing serves as critical barrier to ensure well integrity throughout the production lifecycle. To achieve this, the authors have deployed a structured approach focused on designing for success and optimizing a set of key performance indicators (KPIs) with pre-and post-drilled hole conditions. This paper outlines the approach based on the experience from the drilling campaign of nine oil producer wells.