bluuebunny/crossref_metadata_2025_split huggingface dataset:
Capillary Pressure Effects on Estimating the EOR Potential during Low Salinity and Smart Water Flooding
Authors: Østebø Andersen Pål 
Published: October 2018

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 &gt;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

Abstract
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

Abstract
Shale reservoirs contain predominantly micro and mesopores (&lt;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.