bluuebunny/crossref_metadata_2025 huggingface dataset:
An Embedded Downhole Conductance Sampling System Based on Adaptive FFT Algorithm
Authors: Yang Qinghai , Fu Tao , Huang Shouzhi , Ming Eryang , Li Ming
Published: October 2018

The salinity measurement of the down-hole water is an important parameter to optimize a production scheme for oil exploitation. However, salinity is generally measured offline by physical and chemical analysis and it has been difficult to implement a real-time measurement. With the online conductance sensor, the water salinity can be obtained indirectly based on prior knowledge. In order to solve the down-hole salinity monitoring problem, this paper proposes an embedded sampling system for real-time conductance measurement. The conductance sampling system is designed with embedded technology to achieve continuously monitoring. Based on an ARM-based embedded kernel, peripheral extended circuits are constructed for the sampling system, including an excitation source, a signal conditioner, an analog-to-digital converter, a memory module, a communication port, and a power supply module. The active excitation source generator can output a sinusoid signal with an adjustable amplitude and frequency to the electrical poles. The voltage signal from measurement poles is then sampled after adaptive signal conditioning. With a simplified Fast Fourier Transform (FFT) algorithm, the effective value is measured and the quality of the sampled signal is analyzed to feedback-regulate the excitation source and conditioner. Therefore, the stability and accuracy can be improved for conductance measurement. The conductance measurement system is tested in a physical testing environment with different conditions of water salinity, oil-water mixing ratio, liquid temperature and flow rate. Testing results show that the sampled conductivity value keeps stable and accurate with the calibrated reference conductance meter. The system has a wide measurement range together with a high accuracy and resolution. When the temperature changes, the measured conductivity value basically does not vary, which shows that the temperature compensation is effective. When measuring different salinities of water, the system can adaptively adjust the output amplitude and signal conditioner gain to get suitable sampling precision. In brief, the system provides real-time conductance measurement and the measuring accuracy can satisfy the requirements of petroleum production optimization. To ensure the system may be run down-hole permanently, the electronic scheme and the power supply circuit are specially designed with low-power consumption.
A Comprehensive Study on Ultimate Recovery and Optimum Production Strategy for Gas-Condensate Reservoirs under Aquifer Support in Nam Con Son Basin, Offshore Vietnam
Authors: Tran Tung V. , Truong Tu A. , Ngo Anh T. , Hoang Son K. , Trinh Vinh X. , Dang Tuan A. , Ngo Hai H.
Published: October 2018

Despite the importance of determining the maximum recovery and optimum production strategy for gas-condensate reservoirs under aquifer support, a rigorous systematic methodology is not available in the literature. Instead, most existing studies relied on running reservoir simulations with fine grids or LGR constrained by simulation runtime, producing great uncertainty in the reliability of the results. In this study, a comprehensive and systematic study of gas-condensate reservoirs under aquifer support was conducted instead.

This study focused on first benchmarking radial simulation models to available analytical solutions to within 1% of pore pressure prediction. Next, Cartesian grids were benchmarked against the calibrated radial model before applying to full field reservoir model. The full field reservoir model was then history-matched for all wells before various production regimes were simulated to determine optimum production strategy. Sensitivity analysis of water-breakthrough and total produced water volume were investigated under various aquifer sizes, formation reservoir properties, and production regimes. Optimum production strategy was selected to maximize the hydrocarbon recovery while reducing the water treatment costs.

The approach focused on the construction of benchmarked models to describe the water breakthrough phenomena and to investigate the impact of aquifer on deliverability and ultimate recovery of a gas-condensate reservoir. Factors that could affect recovery such as withdrawal rate, aquifer size, formation permeability, and vertical-to-horizontal permeability were examined. Different production schemes were then simulated on a history-matched full field model to determine optimum strategy.

It was found that for better reservoir quality (permeability greater than 100 mD), withdrawal rates do not have significant impact on ultimate gas recovery. On the other hand, with increasing withdrawal rate cumulative condensate recovery decreases and total water production increases. Aquifer size has large impacts on recovery factor, water breakthrough time, and total water production. For medium and strong aquifers, it was found that the field water handling capacity could impose a significant constraint on ultimate recovery and upgrading water handling capacity later in the field life may be instrumental in improving recovery.
Laboratory Study of Anisotropic Permeability of Tight Sandstone and Shale from Cooper Basin, Australia
Authors: Pan Zhejun , Heryanto Deasy , Down David , Connell Luke , Camilleri Michael , Tan Yuling , Sander Regina
Published: October 2018

Cooper Basin is one of the most important onshore oil and gas producing basins in Australia. It also has the most prospective unconventional tight gas and shale gas opportunities. As tight sandstones or gas shales have low permeability, understanding the permeability behaviour is important for the production of these gas resources. In this work, tight sandstone and shale samples were obtained from an exploration well in the Cooper Basin, Australia, and they were cut into cubic samples with about 30 mm on each side using a wire saw. The cubic sample was then placed in a 3D printed membrane, therefore, permeability along each directional axis can be measured. Methane was used to characterise the permeability. Effects of gas pressure and effective stress were studied with gas pressure up to 9.5 MPa and effective stress up to 7.0 MPa. The results shows that the shale has strong permeability anisotropy at different direction. The sandstone sample also showed anisotropic behaviour, but not as significant as the shale. Finally, a reservoir simulator, SIMED II, is used to study the gas production from tight sandstone and shale using hydraulic fractured vertical and horizontal wells. The simulation results show that permeability plays a critical role in the gas production behaviour from tight sandstones and shales.
Enhanced Oil Recovery by Nanoparticle-Induced Crude Oil Swelling: Pore-Scale Experiments and Understanding
Authors: Agrawal Devesh , Xu Ke , Darugar Qusai , Khabashesku Valery
Published: October 2018

Nanoparticle (NP) based enhanced oil recovery (Nano-EOR) has been considered as a promising future EOR strategy. However, although many mechanisms of Nano-EOR have been proposed, a lack of direct connections between the pore-scale mechanisms and the macro-scale oil recovery performance makes it hard to determine which mechanisms are dominant. In this work, we discovered a novel phenomenon of nanoparticle-crude oil interaction in pore-scale. Multi-scale experiments were conducted to connect this novel pore-scale phenomenon's role to oil recovery performance.

A microchannel with dead-end pore was used to observe crude oil-NP interactions, on which crude oil can be trapped in the dead-end pore with a stable crude oil-aqueous phase interface at the pore-throat. A glass porous micromodel was used to conduct oil displacement experiments. ASW was used as the secondary flooding fluid, and 2000 PPM negatively charged NP in ASW was applied as the tertiary flooding fluid. Saturation profiles were recorded and analyzed by advanced image analysis tools. A coreflood through the sandstone sample was also conducted with similar conditions to the micromodel-flood experiments.

A phenomenon that has never been reported was observed from the dead-end pore microchannel. It was observed that crude oil can considerably swell when contacting the nanoparticle aqueous suspension. In an ideal case (5 wt% NP in DI water), the oil volume more than doubled after a 50-hour swelling. The possible explanation for the crude oil swelling could be spontaneous formation of water droplets in the crude oil phase. NP can very likely affect the distribution of natural surfactants in crude oil (on the interface or inside oil phase), which breaks the water balance between aqueous phase and crude oil. This view has received support from quantitative experiments. It was shown from 2.5 D micromodel flood experiments that 11.8% incremental oil recovery comes slowly and continuously in more than 20 hours (40 pore volumes). From a saturation profile analysis, swelling of crude oil was found to improve sweep efficiency. Coreflood experiments also showed that the incremental oil was slowly and continuously recovered in about 20 hours during NP flooding. We propose that reduction of local water mobility by oil swelling in the swept region is the mechanism of sweep efficiency improvement.

Swelling of crude oil under a NP environment was observed for the first time, with a systematic theory proposed and examined by quantitative experiments. The micromodel flood and coreflood experiments showed slow incremental oil recovery with a similar time scale to the oil swelling. Image analysis on the micromodel flood demonstrated improvement in the sweep efficiency during NP flooding. The mechanism for this sweep improvement is proposed.
Zonal Isolation of a Fractured and Gravel Packed Water Producing Zone using an Organically Crosslinked Polymer Sealant: Case Study
Authors: Nagar Ankesh , Dangwal Gaurav , Pandey Nimish , Jain Akanksha , Parasher Arunabh , Deshpande Mayur , Gupta Vaibhav , Pande Karan
Published: October 2018

Increasing water cut in oil-producing zones is a common issue faced by operators, particularly for mature fields. Currently, where most of the decisions are governed by economics, incurring additional expenses with activities such as handling produced water becomes extremely undesirable. Depending upon the nature of the zone, one effective solution to this issue is chemical isolation. This paper undertakes this issue, discussing a case study of a successful zonal isolation operation using an organically crosslinked polymer sealant in a fractured zone with a gravel pack and screen completion for a reservoir with a subhydrostatic nature.

This zone was an initial oil producer in FM-01 sand of the Mangala onshore oil field and had been stimulated in 2011 with a fracture-pack completion. The zone was completed with screens and a gravel pack with 16/30-mesh sand and 5.5-in. screens across the producing interval. During a period of time, the zone (FM-01) began to produce a significant amount of water, resulting in excessive water cut. To mitigate the issue, it was decided to completely isolate the zone using an organically crosslinked polymer system as a porosity fill sealant. When prepared in the appropriate concentration, subject to reservoir temperature, this low-viscosity formulation (40 to 80 cp) turns into a permanent rigid gel with time. The particular challenges of this operation were the presence of high permeability streaks because of stimulation by hydraulic fracturing, extra pore space because the perforated interval lay within the gravel-packed screens, and the subhydrostatic nature of the reservoir. Extensive laboratory testing was performed to optimize the formulation at the desired temperature, measuring the time necessary for the viscosity to begin increasing and the minimum total time necessary to form a rigid gel.

The case study discussed in this paper features the successful application of the treatment using the spot-and-squeeze method with coiled tubing (CT) for the isolation of the zone. After allowing the setting time, pressure tests were performed, indicating positive isolation of the zone. After the pressure test, a jet pump was installed, and a drawdown was created to flow the zone. It was observed that production post operation was almost 95% less than production before operation at the same pressure drawdown, indicating approximately 100% zone isolation.
How to Run Casing Efficiently in Extended Horizontal Wells Using Buoyancy
Authors: Rastegar Reza , Munawar Mohammed , Tait William
Published: October 2018

Due to drilling economics, operators prefer extending the lateral section over drilling a new well. It presents a challenge to run casing strings to the target depth in wells where horizontal section is longer than the vertical section. Although alteration of casing weight or installation of liner may present as solutions, they are hardly economical compare to selective buoyancy methods. This paper aims to take an engineering approach on optimizingly palceing a buoyancy barrier which traps lighter fluid in the horizontal section for thepurpose of reducing friction. As seem to not have been presented in SPE conferences before, the aim of this paper is to engineeringly identify the optimum placement of the barrier, measure the efficiency improvement and identify the cases for which running a barrier is essential to run the casing string to the target depth. Operators usually run a torque and drag to measure the improvemet made by placing a barrier in kick off point. In this paper we intended to verify this practice and offer a simple rule of thumb method that can help an operator to decide on weather it is needed to run a barrier.

Referred to in this paper as flotation collar, it is installed as part of the casing string. It employs a mechanical barrier that traps the air or lighter completion fluid in the mostly horizontal section and separates it from the heavier completion fluid in the mostly vertical section of the casing string. Identifying the best position of the barrier is important to achieve the maximum hook-load. In this paper, numerous cases are studied by gradually expanding the air section and monitoring the hook-load to identify the best position for which the hook-load is maximum.

As per its physics, there is only one position of placement which results in the highest axial tensile force, also known as hook-load, when forces of gravity and friction engage. Placing the tool too high or too low in the string misuses the available tensile axial force and will not provide the best results. By using casing flotation tools as a barrier, a spectrum of thirty to eighty percent tensile improvement in the axial load are observed and more than fifty percent reduction of buckling effects in vertical section. For some cases, running a flotation tool was the only option to reach to the target depth with the casing string.

Flotation tools in long string wells are the only economical alternative to changing casing weights or running liners when it is to completing wells with extended horizontal sections. A flow-chart is presented to help with simplifying the process of choosing a flotation tool and finding its best position of placement.
Capillary Pressure Effects on Estimating the EOR Potential during Low Salinity and Smart Water Flooding
Authors: Østebø Andersen Pål
Published: October 2018

Many experimental works have investigated smart water and low salinity water flooding and observed significant incremental oil recovery following changes in the injected brine composition. The commonway approach to model such EOR mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness may retain much oil at the outlet of the flooded core due to capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in high permeable cores at typical lab rates. Injecting a brine that changes the wetting state to less oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation.

This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing core flooding accounting for wettability changes due to changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability alteration component coupled to shifting of relative permeability and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically due to changing one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including 1) changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and 2) the magnitude of capillary end effects can be reduced due to increased water-wetness or due to reduction in water relative permeability giving a greater viscous drag on the oil.
Introduction of Real-Time Flow Measurements Opens New Paths to Overcome Challenges Encountered During the Acid Stimulation of Extended Reach Wells
Authors: Duthie Laurie , Saiood Hussain , Almarri Hamad , Ahmed Danish
Published: October 2018

Challenges are usually exaggerated related to matrix acid stimulation and fluid placement in extended reach horizontal wells and demand a constant flow of innovation. The optimization of real time fluid placement, increasing the reservoir contact and establishing uniform fluid distribution for better production/ injection across the openhole interval is one area that can benefit from these new innovations.

Coiled tubing (CT) equipped with a tractor and new real-time downhole flow measurement capabilities was selected as the solution. While a CT tractor facilitates the reach, flow measurements provide a clearer understanding of downhole injectivity patterns. Real-time fluid direction and velocity are acquired and used to identify high/low intake zones. The data is subsequently applied to adjust the stimulation diversion schedule accordingly. In a water injection well, baseline data was acquired before commencing a matrix stimulation treatment. The treatment was squeezed through the CT at the depths highlighted as low intake during the initial profiling.

The coiled tubing real-time flow tool was deployed during the matrix stimulation treatment of the extended reach water injection well with a downhole tractor. The flow tool measured the baseline injection profile which was then correlated with the mobility data. Results from the pre-stimulation profile showed that 70% of injection was entering in a 3,000 ft. section near the toe (24,500 ft.), whereas 30% of injection was spread across the remainder of the open-hole interval. The acquired flow data was able to identify sections of the wellbore featuring low mobility and viscous fluids, which in turn provided additional information for the adjustment of the subsequent stimulation pumping sequence. The real-time optimization of stimulation treatment helped to increase the post-stimulation injection rate by over 4 times the pre-stimulation rate.

The combination of CT tractor with real-time flow measurement tool provides an efficient means to stimulate extended-reach water injector wells. The basic technology behind the real time flow tool is a synchronized system with a series of heating elements and temperature sensors along the tool to determine the direction and mean velocity of the fluid. This ultimately allows for a more accurate placement of stimulation treatment to the targeted zones. The technology can also be applied for extended reach oil producers, however, for optimum tool performance, the well should first be displaced with an inert fluid.
Statistical Decline Curve Analysis for Automated Forecasting of Production from Coalbed Methane Wells
Authors: Kuznetsov Dan , Fernandes Glen , Daly Michael , Ma Kai
Published: October 2018

In this paper, we introduce a methodology for the automated construction of a statistical forecast for gas production from coalbed methane wells. The approach uses decline curves to extrapolate production from individual wells and provides a statistical range of outcomes based on a regression model, fit to a cluster of wells similar to the one being forecasted. The purpose of the method is to provide a quick forecast that uses only directly measured data that are subject to a minimal additional interpretation and modelling. In the paper, we describe application of the workflow to forecast production from previously produced and newly drilled horizontal coal-gas wells in the Bowen basin and compare predictions to the actually observed production.

First of all, we benchmarked different types of decline curves against numerical simulation to evaluate the applicability of decline curves for long term predictions. We checked Arps's and power-law and exponentiated exponential family of type curves to predict production for up to 30 years. When compared to the simulation results, Arps's curves provided the best match.

Then, we introduced a type curve fitting workflow and compare prediction against observed production for each type of decline curves at prediction period from three months to five years.

After that, we evaluated different regression models (linear, kernel density estimate, agglomerative clustering, Bayesian combination of linear regression and clustering, support vector and random forest) to predict the peak rate and provide a way to extract the decline statistics for similar wells.

The combination of type curves and a regression model allowed us to construct a distribution of decline curves for each well and extract curves corresponding to the requested quantiles. We applied this statistical approach to production of 140 wells and compared the predicted results with the actual production.

In the end, we discuss how this workflow can be applied to forecast production from the new infill wells. The only essential difference is that the peak rate needs to be adjusted to take the depletion into account. That can be done by multiplying the peak rate estimate by the ratio of inflow rate at the time of the historical peak and the current time. The inflow ratio can be estimated by comparing the average reservoir pressure at both moments in time.

We used this workflow as a part of the screening process to select infill well candidates. In the paper, we compare the results of the prediction with the actual production from 15 infill wells drilled within two years form the time of the forecast.
First Mobile CNG: Conversion of Waste Gas for Improving Oil Recovery and for Gas Monetisation
Authors: Juljumroensub Chadakarn , Sonsayan Pachachit , Thippayawarn Anucha , Sitthichaikasem Valeeporn , Sunsap Piyabutr , Langkulanont Nontacha , Panichpongsakorn Nattaphat , Nitayaphan Saranee
Published: October 2018

S1 production at the Outstation (O/STN) is about 30% of S1 crude oil production or at the flow rate of approx. 8,000 bbl/day. At present, S1 O/STN production comprises of 16 areas which are 7 permanent production facilities and 9 mobile production facilities (MPF). Some of the permanent production facilities can monetize the associated gas while all of the MPF associated gases have to be flared. Currently, the average total flare rate at O/STN is approx. 3.3 MMSFCD while average flare gas rate by location is vary in the range of 0.1- 0.5 MMSCFD. Recovering these gases, that would normally be flared, and converting them to CNG will give both economic and environmental benefits to our company, PTTEP.

Therefore, this project has been executed as a pilot project in order to reduce greenhouse gas emission, flaring light, and other pollutions to support company vision by connecting at flare gas line from MPF to CNG Compressor Package and discharge to CNG trailer. Then, CNG trailer will discharge CNG to the hub station for futher utilization.

MPF locations which will be used for trial the pilot mobile CNG unit is SPA-D which has total flare gas rate between 0.1 MMSCFD to 0.5 MMSCFD. Therefore, the capacity of the pilot mobile CNG unit is designed at the capacity of 0.22 - 0.35 MMSCFD with VSD function to cover fluctuations in the gas production from wells.

NTM-A location is selected to be used as a destination for utilizing CNG. CNG utilization can be maximum used in 3 steps which are: Step 1: pressure 3,600 - 1,350 psig, CNG will be used as a gas lift to enable oil gain from gas lift wells.Step 2: pressure 1,350 - 450 psig, CNG will be discharged directly to flowline for selling at production station.Step 3: pressure 450 - 45 psig, CNG will be discharged to separator before compressed again by a booster compressor and then routed to flowline for selling at production station.

To enable CNG utilization in various steps, a pressure reducing unit (PRU) is designed to perform all the required functions.

The pilot mobile CNG unit can bring back flare gas for untilization is at 0.3 MMSCFD. It helps reduction CO2 emission for approx. 6,520 ton per year. Combination benefits of CNG can increase crude oil production for 25 bbl/day from gas lift and then being sold to 3rd party at production station.
EOR RMP: Addressing Key Risks Through Sound Reservoir Management
Authors: Sifuentes Walter , Mandal Dipak , Kumaran Prashanth Nair , Ibrahim Ramli , Chabernaud Thierry , Ceccarelli Tomasso , Moreno Juan Carlos , Sepulveda Willem
Published: October 2018

This paper aims to describe the overall EOR GASWAG concept with some of the key findings after first phase execution and some of the measures taken to maintain the project within the planned OPEX to remain economic. Secondly, to describe a comprehensive reservoir management plan which includes a fit for purpose data acquisition plan and more importantly how the remaining challenges are addressed through the RMP optimization to maximize recovery. Finally, this paper outlines the main key challenges to be faced once the injection phase kicks off, highlighting the surveillance and monitoring strategies to overcome them.
Value Creations through Tangguh Big Gas Well Daily Surveillance Integration Challenge
Authors: Kartawijaya Ian Adrian , Menanti Yoseph , Saraswaty Dhita , Suganda Singgih , Iqbal Muhammad , Anantokusumo Ferry , Dinata Randy Chandrana
Published: October 2018

Managing big gas well requires careful monitoring to ensure optimum wells production within their operating envelopes whilst continuously obtaining production data. Such data improves subsurface understanding over time and become a basis for optimization exercises, wellwork initiation, and quick corrective actions. Tangguh all-inclusive well surveillance integrates various daily data analysis into an efficient well surveillance process. It essentially looks for both early problem signs and improvement opportunities, enabling ahead anticipations.

Tangguh real time surveillance allows continuous parameter monitoring: pressures, temperatures, choke opening, multiphase flowrates, sand detection, annuli pressures, and system backpressure. A semi-automatic system then integrates all available data quickly and allow engineers to perform meaningful analysis timely. The integration is a significant upgrade over the past surveillance practice, where typically more time spent on data gathering instead of the analysis; and missing anomalies that happened in unmonitored parameters while concentrating on a specific parameter.

Combining with some non-routine data acquisitions, this well surveillance integration enables a quick and thorough well performance review and assists unlocking optimization opportunities. Three examples below demonstrate value creation from the integrated well surveillance.

First example: combining real time well data and the non-routine acquisitions enable robust well productivity model construction. This has improved the understanding of each well productivity and operating limits, which upon evaluating lead to deliverability increases by simple well limits upgrade and debottlenecking projects. Other result includes assistance in defining restoration wellwork candidate.

Second example: by continuous comparison between real time data and calculated performance model, the surveillance has shown its ability to detect well choke trim damage while flowing. This successfully prevented problem escalation into a more serious safety incident, such as gas release from an eroded choke valve.

Third example: despite the challenges in accurate dry-gas-well liquid rate measurement, continuous water source identification is applied honoring the significant reserve it may impact, starting from routine salinity monitoring, theoretical condensed comparison against receiving facility figures, and material balance plots. All positively indicate no aquifer breakthrough yet so far.
Realising Additional Value from Late Life High Water Loaded Gas Wells through Transient Flow Modelling
Authors: Wong Jeannie C. , Ghous Abid , Morgan Julie E. , Hourani Mohamad Yousof
Published: October 2018

As gas fields mature and water production increases, understanding and managing the dynamic flow behaviour of the well and production system are critical for maintaining, and even optimising, production. This knowledge could be the difference between a successful and an unsuccessful attempt at re-starting a wet gas well after it is shut-in. When a well is in production, choking the well to optimise stable facilities operation and maintain water production within the water handling constraints of the facilities can be a fine line between achieving continuous stable production and the well ceasing production due to high liquid loading.

This paper describes the successful kick-off and unloading of two high-water producing gas wells within the operational constraints of the offshore facility. Transient multiphase flow models were developed for a platform well and a subsea well to simulate the wellbore flow dynamics during start-up. The models were tested over a range of values for parameters such as reservoir pressure, inflow performance and water gas ratio for different kick-off strategies but always honouring the facility's water surge management constraints.

The outcome of these simulations facilitated the development of tailored bean-up strategies for each high-water producing gas well, which provided a mechanism to engage with key stakeholders and demonstrate confidence in the execution of these strategies. Dedicated procedures were developed and subsequently executed successfully to re-start the two wells with the wells continuing to produce after kick-off and unloading, operating within the water surge management limits of the facility. Similar strategies are being developed for other high-water producing gas wells including those with material sand production.

This paper demonstrates strategic capability to realise additional value using dynamic modelling to kick-off mature high-water producing gas wells through proactive development of mitigation strategies which avoid production disruption.
Carbon Dioxide in Reservoir Gases: New Insights from Basin and Petroleum System Modeling
Authors: Koronful Nour , Peters Kenneth , Ali Mohd Firdaus , Skulsangjuntr Jirapha , Jiang Long , Kleine Adrian , Basu Depnath , Bencomo Jose , Hernandez Jonathan , Brink Gerhardus
Published: October 2018

High carbon dioxide in reservoirs limits successful exploration in many petroliferous basins, particularly in Southeast Asia. High reservoir CO2 in the offshore Malay Basin represents a significant exploration challenge. Some fields contain >80% CO2, which makes them unattractive targets for development. Various hypotheses on the origin of CO2 have been proposed but remain controversial. This paper shows that geochemistry and advanced petroleum system modeling help to resolve the origins of reservoir CO2 and allow quantitative estimates of CO2 in prospective reservoir targets prior to drilling. A novel workflow estimates the CO2 content in reservoirs based on knowledge of the chemical mechanisms for the origin of the CO2 and numerical simulation of geologic burial history. Heat flow, deposition of overburden rock, and the kinetics of specific reaction mechanisms control the timing of CO2 generation and the relative contributions of CO2 from different sources.

In this study, stable carbon isotope ratios of CO2 and methane (δ13CCO2 and δ13CCH4, ‰) were used to identify the source of the CO2 in Malay Basin gas samples. For example, Figure 3 shows δ13CCO2 and δ13CCH4 for samples from various depths in the nearby field. The isotope data indicate that the samples contain mixed CO2 derived by different mechanisms from two sources. Partial least squares (PLS) regression of δ13CCO2 and δ13CCH4 and depth for 61 samples from the nearby field, where %CO2 was set as the dependent variable, resulted in a systematic correlation between predicted and measured %CO2. Alternate least squares (ALS) confirms that the data can be explained by mixing of gases from two endmembers: (1) shallower samples show lower %CO2 that is isotopically depleted in δ13CCH4 and δ13CCO2, and (2) deeper samples show higher %CO2 that is isotopically enriched in δ13CCH4 and δ13CCO2. The relative proportion of each endmember in the mixture can be calculated for each gas. Examples of near endmember gases in the nearby field (Figure 3) are: (1) shallow thermogenic CO2 derived by cracking of kerogen, e.g., 1681 m, 5% CO2, δ13CCH4 = -60‰, δ13CCO2 = -13‰, (100:0 mix); and (2) deep CO2 from carbonate decomposition, e.g., 2918 m, 74% CO2, δ13CCH4 = -32‰, δ13CCO2 = -3‰ (15:85 mix). These results are consistent with the general observation that tested Miocene traps in the Malay Basin and show a general trend of higher concentrations of CO2 in the deeper traps that are nearer carbonate basement. Biogenic CO2 may represent a third endmember in other parts of the basin.
Managing Complex, Laterally and Vertically Compartmentalized Reservoirs in a Subsea Tie-Back via Smart Well Completions – Case Studies
Authors: Smith Neil , Ghous Abid , Bharatiya Sagarika
Published: October 2018

This paper presents case studies on reservoir and well management of two laterally and vertically compartmentalized Western Australian Triassic gas condensate reservoirs, developed by five multi-zone "smart" wells with sand control, tied back to an offshore platform via a subsea network. In managing assets with such complexity, it is imperative to understand reservoir performance on a zone-by-zone basis. Quantifying performance allows management of flux through downhole sand control systems and optimisation of offtake strategy. The majority of the material published to date on "smart" wells has been focused on completion design optimisation and minimisation of unwanted oil/water production. There are few existing articles about production and reservoir optimisation of high rate gas wells requiring flux management.

This paper showcases how remotely-operated selective completions ("smart" wells with permanent downhole gauges for each completion coupled with subsea flow meters for each well) have been instrumental in facilitating prompt analysis of zonal reservoir performance and thus in yielding insights into reservoir connectivity and allowing optimisation of zonal contributions. Various case studies will be presented showing how reservoir surveillance data is acquired and interpreted to optimize well zone-by-zone production and to manage flux limits on each producing zone. These case studies will include manipulation of downhole valves to provide information for established techniques such as interference testing and P/Z analysis.

Data acquisition and interpretation challenges are highlighted along with fit-for-purpose solutions developed to overcome those challenges.

The insights presented could facilitate better planning of similar systems in the future.
A Model of Gas Transport Through Shale Reservoirs Including the Effects of Real Gas, Gas Adsorption and Stress Dependent Permeability
Authors: You Nan , Lau Hon Chung
Published: October 2018

Shale reservoirs contain predominantly micro and mesopores (<50 nm), within which gas is stored as free or adsorbed gas. Due to the ultra-small pore size, multiple transport mechanisms coexist in shale reservoirs, including gas slippage, Knudsen diffusion of free gas and surface diffusion of adsorbed gas. In this work, we propose a new transport model, valid for all ranges of Knudsen number, which combines all transport mechanisms with different weighting coefficients. To quantify the effects of influence factors, we introduce the compressibility factor for real gas effect and effective pore radius for gas adsorption and stress dependence. The model is proven to be more accurate than existing models since the deviation of the analytical solution of our model (3%) from published molecular simulation data is lower than that of existing models (10~20%). Based on this model, we compare (1) the contribution of each transport mechanism to gas transport in pores of different radii, (2) shale permeability measured in laboratory and at reservoir conditions, and (3) permeability of nanopores and natural fractures. It is found that gas transport is dominated by gas slippage and surface diffusion when the pore radius is over 10 nm and below 5 nm, respectively. Knudsen diffusion only becomes significant when the pore radius is between 2 and 25 nm and pore pressure is below 1000 psi. Furthermore, laboratory measurements usually over-estimate shale permeability. We also propose a promising enhanced gas recovery method, which is to open and prop up closed natural fractures using micro size proppants.
Optimized Alkalinity for EOR Purposes in Sandstone Reservoirs
Authors: Mamonov Aleksandr , Khan Md Ashraful , Puntervold Tina , Strand Skule
Published: October 2018

With increased environmental focus and sustainability, classical water-based EOR with surfactants or polymers meet larger implementation scepticism. This has increased the attention toward water-based EOR methods with low environmental impact and lower costs, such as Smart Water and alkaline flooding. Both methods are based on the establishment of alkaline conditions in the formation. Chemical interactions among the rock minerals, reservoir fluids, and injection brine can be reflected in the pH of the produced water. Thus, the scope of this work is to investigate the development and transportation of pH through porous media during 1) low salinity (LS) Smart Water flooding, and 2) alkaline LS (alk. LS) waterflooding.

Outcrop sandstone cores were used in core flooding experiments. Several pH-screening tests were performed to study the pH development during waterflooding. The ability of LS and alk. LS injection brines to increase the pH in sandstone core material with different mineralogy was compared, and the effect of pH on oil recovery was confirmed in an oil recovery test.

The results of the pH-screening tests by LS brine injection showed a potential for increasing the effluent LS water pH up to 2 units in comparison to its initial pH-value. The oil recovery test performed on the same core material showed almost 10% incremental oil recovery during LS flooding in secondary mode, in comparison with formation water (FW) flooding. pH-screening tests with alkaline LS brine injection showed low potential for extra alkalinity above that obtained by LS brine injection. Transportation of alkalinity through a mineral system with large surface area seemed to be challenging due to pH buffering from brine/mineral interactions as well as from chemical interactions involving inorganic cations from the formation water.

Based on the experimental results, ion exchanges between rock minerals and injected water can influence the reservoir pH and induce the wettability alteration. These chemical interactions can result in both development and consumption of alkalinity depending on the type of injected brine and chemical reactivity of the minerals. It was concluded that an in-situ generation of alkaline conditions at the waterfront seemed to have larger potential for EOR purposes than transferring the alkalinity of the injected brine through the reservoir.
Hydraulic Fracturing Treatment of Low-Permeability Coal Seam Gas Reservoirs with Finely Layered Coals
Authors: Zhang Xi , Wu Bisheng , Connell Luke , Han Yanhui , Jeffrey Robert
Published: October 2018

In this paper, a fracture mechanics model that deals with fracture growth in layered low-permeability rocks is presented and applied to hydraulic fracturing stimulation of coal seam gas reservoirs. The model uses the conventional pseudo-3D treatment by which the vertically planar fracture is divided into cells along the horizontal direction. For each cell, the fracture deformation is represented by a 2D plane-strain fracture. To ensure numerical stability, the model uses an optimization method based on the fluid volume increase of each cell and the solutions for each cell can be obtained in parallel when using a computer with multiple CPU cores. The method was verified based on the comparisons with existing solutions and the computational speed can be significantly increased by using parallel computing. Numerical examples are presented to illustrate cases that result in fracture geometrical complexities caused by material properties contrasts between the thin softer coal seams and the adjacent stiffer rocks. The local horizontal stresses in each layer are calculated based on the layer-independent uniform horizontal strain assumption. The overburden stress is given. The fracture length and opening in the coal can be larger than other layers if the coal is subject to a smaller stress. This will promote growth of the fracture plane to include coal seams that do not receive injected fluid at the wellbore. The well developed fracture opening in the coal can be impeded by an increase in the confining stress of the coal. The fracturing produces wide propped channels below the coal seam in the low stress rock that exists there. These conductive channels allow flow of gas and water to the wellbore. The stress uncertainty is considered and interestingly the injection pressure trends are insensitive to the variation of local stresses. There is a process that favors growth in the softer coal seams for all cases, which yields a slight and progressive increase in the injection pressure.
Planning and Drilling Execution of Early Permian Wells in Two String Design by Implementing New Drilling and Cementing Technologies
Authors: Shaban Alex , Zaman Mohammad , Dedigama Thivanka , Saunders Troy
Published: October 2018

The development of Early Permian reservoirs in the Fairview Field is limited by highly depleted shallower Bandanna coal seams and naturally fractured formations that would not allow to reach the original geological goals. Offset wells in the area had been executed as three string well design due to long open hole section across depleted Bandanna and multiple loss zones. Multi-stage cementing was required to ensure there is proper zonal isolation. These resulted in significant incremental cost to achieve 5-1/2″ production casing. Through the depletion of upper coals, fracture pressure in these zones has decreased due to reduction in pore pressure.

Drilling in two string design carries higher execution risk due to long open hole section, depleted formations and differential sticking, highly fractured formations, narrow window between fracture gradient and pore pressure, and multiple loss zones which demands special techniques for treatment of loss zones and hole stabilisation while drilling. Considering the downhole conditions, which pore pressure ranging from 2 to 9 ppg in the different formations, the importance of zonal isolation, establishing barriers in aquifers and achieving overall cement coverage is also extremely important.

With introduction of various new LCM products, cement plugs, foam cementing, RCD for drilling with no returns (blind drilling), Santos has achieved major success developing Early Permian fields. This Paper describes how two string design was successfully implemented to drill Early Permian wells. This paper serves as an operational guide to ensure challenging depleted and highly fractured zones can be successfully drilled while minimising risks.
Quantifying Gas Content in Coals Using Borehole Magnetic Resonance
Authors: Hopper Timothy , Neville Thomas , O'Neill Keelan
Published: October 2018

Traditional approaches to saturation evaluation in conventional oil and gas reservoirs rely on relationships between resistivity and water saturation. These relationships are challenging to apply in coals due to complexities in their pore systems and gas trapping mechanisms. Therefore, geophysical log-based methods are not commonly employed for saturation evaluation, and core canister desorption measurements are the standard approach for gas content evaluation. Desorption measurements present their own challenge due to the unknown and variable volume of gas lost during core recovery, so an in-situ measurement of gas content is desirable.

Advanced magnetic resonance measurements provide a resistivity-independent saturation evaluation that have been employed in the oil and gas industry for the past approximately fifteen years. However, previous approaches to these types of measurements have focused on the evaluation of conventional reservoirs and hence free gas, oil, and water volumes, and have lacked sensitivity to quantify adsorbed gas, which has a unique magnetic resonance response. A novel magnetic resonance acquisition scheme has been developed that provides sensitivity to both adsorbed and free gas, as well as water, allowing for the complete evaluation of fluid content in coal seams. This measurement has been employed in evaluating coal gas content for coal seam gas evaluation and coal mining optimisation with encouraging results.
Mechanistic Modeling of Low Salinity Water Injection under Fracturing Condition in Carbonate Reservoirs: Coupled Geochemical and Geomechanical Simulation Study
Authors: Hosseini Seyed Moein , Kord Shahin , Hashemi Abdolnabi , Dashti Hossein
Published: October 2018

The main problem during field scale implantation of low salinity water injection (LSWI) is the decline in injectivity versus time. Moreover, the actual mechanisms that result in incremental oil recovery are not completely known. In previous studies, the geomechanical effects have not been considered, and pore volume changed while bulk volume is still constant which in turn can bring uncertainty to the simulation results. In this paper, both geochemical and geomechanical models have been coupled with the flow model. For coupling geomechanical model, three equations have been solved simultaneously in each time step. Then, the geochemical model has been coupled by adding the necessary aqueous and mineral reactions and ion concentration of both formation and injection waters. Increasing the Ca2+ concentration in the injected brine cause a reduction in the ultimate oil recovery. Also, increasing SO42− concentration in the injected brine up to about 70 ppm, resulted in increased oil recovery, while increasing the concentration caused a reduction in oil recovery. Injection above formation parting pressure (FPP) is beneficial but, there is a high uncertainty during injection above the FPP that can affect ultimate oil recovery and net present value. The results of this study show that geomechanical and rock parameters have intensive effects on the simulation results and rough estimating them in the simulation process can result in major errors and uncertainties. Further, it is very important to precisely include the dominant mechanisms of low salinity or smart water process during simulation studies.