bluuebunny/crossref_metadata_2025 huggingface dataset:
Initiatives in Cooperating with Local Government and Communities Promote the Development of a HTHP Gas Field in Remote Area of China: Development of Keshen Gas Field
Authors: Jiang Tongwen , Liu Huifeng , Yang Xiangtong , Liu Yuan , Feng Jueyong , Ren Huining , Guo Hu
Published: October 2018

Keshen gas field is located in the southern foothill of Mount Tianshan, Western China. Administratively it belongs to Baicheng County, a poor and remote county. This county is composed of 20 ethnic groups, who have their own cultures and languages, which pose difficulties for project management. With a series of initiatives for cooperating with the local government and communities, a yearly natural gas productivity of 5 billion cubic meters were established within five years.

A series of measures were taken to win the support of local government. A 108-kilometer long highway was constructed in the mountainous area and shared with local communities. A pipeline network was established to transmit natural gas from Keshen gas field to the suburban areas of Baicheng and other remote places, which changed the local main fuel from firewood into clean natural gas. We hired local people, trained them and gave them decent salaries. More than 2,000 job opportunities were provided to local ethnic minorities, which accounts for 18.5% of the total workers in this project.

Thanks to the initiatives we have taken, a harmonious development mode was established in Keshen gas field. It was put into production within five year's construction. The average productivity of a single well is more than 500 thousand cubic meters. The total amount of taxes as well as the GDP of Baicheng County was twice as before. The southern Xinjiang pipeline network encircles half of the Tarim Basin. 41 towns along the pipeline and 4 million people are benefiting from the natural gas produced from Keshen gas field. In return, the local government and communities provided a lot of conveniences for the project crew. The government released several restrictions on seismic exploration and pipeline construction. Since the project crews were mostly from urban areas, the local residents also help us to recognize risks and formulate risk-reducing practices for conducting engineering work in the Gobi and desert area. We also instructed the local residents to do business with Keshen development project, including selling of construction and living materials, renting of equipment, transport vehicles, etc. This initiative also helped to reduce unemployment rate and benefit the project management as well.

Keshen gas field is one of the most complicated reservoir in China, not only because of the ultra-deep HPHT reservoirs, but also because of the complicated social environment. A win-win cooperation mode between the Oilfield Company and local communities has been established after a series of initiatives. This set a solid foundation for the sustainable development of Keshen gas field and also set an example for the development of reservoirs in remote areas.
Embracing Opportunities and Avoiding Pitfalls of Probabilistic Modelling in Field Development Planning
Authors: Hajizadeh Mobaraki Alireza , Deo Tewari Raj , A Karim Rahimah
Published: October 2018

Uncertainty and risk analysis is an inseparable part of any decision making process in the field development planning. This study sheds light on the available approaches to capture the range of uncertainties but digs deep into the misuses of the probabilistic approach that renders the method difficult and time consuming to implement with little added value for risk mitigation and proper decision making.

Probabilistic modeling using dynamic simulation models has been adopted in recent decades to address the variations in forecasted production profiles and to capture the uncertainties. However, there are misuses in the approach that pose questions on the outcome and its meaningfulness. Lack of enough spread in the forecast, history-matched models with physically incorrect parameter ranges/ combinations and models suggesting contradicting development scenarios are among examples. These in turn make the probabilistic forecasting output inconclusive and considering the high computational cost and time required to perform the exercise makes it unattractive to management. In this paper four case studies including mature and green fields have been described and a number of main issues and pitfalls of using probabilistic dynamic modeling in those cases are analyzed. General workflows are then presented for green and brown fields based on experimental design, proxy modeling, optimization and prediction candidates selection that provides solution for proper selection and implementation of the probabilistic dynamic modeling.

It is argued that probabilistic modeling can help better capture the uncertainties and reduce the risk in field development planning provided that a fit-for-purpose approach is taken with correct understanding of the data requirement according to the reservoir complexity, the physical processes being modeled and assumptions used in the methodologies and simulation engines. This is in contrast to the attempts to capture the ranges of recoverables based on deterministic high and low cases that is often inefficient as the optimistic high-case of ‘hole-in-one’, may suggest an ideal but not plausible scenario whereas the pessimistic low-case of ‘train-wreck’ may be economically unattractive. The exercise then leaves the companies with the best technical estimate model to make the final call and the numbers from other models are only used for reserve booking purposes.

The published papers in the literature include discussions on deterministic vs. probabilistic approaches and selection of base case models, the detailed algorithms and also case studies done using the published methods available in the commercial softwares. This paper however discusses the misuses of the probabilistic dynamic modelling approach and tries to inform the audience of the pitfalls of not understanding the reservoir and/or the tools used in implementing the methods and in this sense it is novel.
Early-Stage Detection of Scales in a Deepwater Field Offshore Ghana via Remote Monitoring of Multiphase Meter
Authors: Darab Mahdi , Nygaard Rune , Singh Arvinder Paul
Published: October 2018

Multiphase metering has enabled addressing a number of flow assurance challenges, including the detection of scale formation. This capability is especially appreciated in subsea fields, where the physical access is restricted and flow assurance challenges can be detrimental to maintaining production with a reasonable cost. The scale detection capability of the multiphase flowmeters using live multiphase flow data facilitates a proactive approach by the operators to detect and remediate productivity and flow assurance issues arising out of scale deposition.

A successful early-stage detection of scales in an oil well in deepwater field offshore Ghana via remote monitoring of multiphase metering data is reported. The displacement of the operating point of the multiphase meter and the swift developments in a matter of days provided the necessary live data for the hypothesis of the scale formation in the meter's venturi. Necessary mitigation action was taken and increases in production due to removal of scale demonstrated presence of scale. An in-house-developed remote surveillance and diagnostic system carried out this detection. The results of this project demonstrate the practical capability of remote monitoring of multiphase metering data for flow assurance purposes.
Statistical Analysis of Effect of Sensor Degradation and Heat Transfer Modeling on Multiphase Flowrate Estimates from a Virtual Flow Meter
Authors: Bikmukhametov Timur , Stanko Milan , Jäschke Johannes
Published: October 2018

Accurate flowrate measurements in petroleum production systems are important for optimization, fiscal metering, and production allocation. Sometimes, Virtual Flow Meters (VFMs) are used for this purpose instead of physical meters to reduce cost. These systems estimate the flowrates using a computational model that represents accurately the production system of interest. Since VFM systems mostly rely on pressure and temperature measurements, it is important to understand how accuracy and degradation of sensors influence the VFM flowrate estimates.

In this work, a VFM system for a subsea oil well was created using a transient multiphase model built in a commercial software and controlled from an external computational routine. A statistical analysis of VFM simulation results was performed to quantify the effect of pressure sensors degradation on the VFM flowrate estimates. In addition, the effect of temperature matching and a segmented approach to represent the well heat transfer were evaluated.

The analysis showed that the sensor degradation effect should be considered in VFM systems carefully, especially if a high estimation accuracy is required. Measurement drift was found to be the most critical factor of the sensor degradation but high measurement noise can also cause considerable errors of the flowrate estimates. In addition, it was found that a complex representation of the wellbore heat transfer is not required to obtain accurate flowrate predictions and simplified models can be used instead.
Design, Fabrication and Field Trial Testing of a Novel Rotating Continuous Circulation Tool RCCT
Authors: Badran Mohammed , Gooneratne Chinthaka , Saqqa AbdulKarim
Published: October 2018

In this paper, we present an innovative Rotating Continuous Circulation Tool (RCCT) that allows both limited rotation of a drillstring assembly and uninterrupted circulation of drilling fluid during making up of, or breaking out, a drill pipe, to/from the drillstring assembly. Continuous/nearly continuous drilling has many advantages such as reducing the risk of stuck pipe and wellbore collapse as well as the efficient removal of cuttings resulting in improved borehole cleaning. The RCCT is a sub with a central bore and upper and lower ends that connect to the drillstring assembly. The upper and the lower part of the RCCT are able to rotate independently and in unison through a clutch/sleeve system. A central bore valve that is coupled to the upper part of the RCCT is able to selectively open and close the central bore. There is also a side entry port in the sidewall of the upper part that is controlled by the central bore valve to selectively allow drilling fluid to be injected into the central bore. A preliminary field trial to validate the RCCT was safely and successfully performed in a hydrocarbon well during a cement cleanout operation. The four RCCT subs were successfully tested for rotation with the rotary table and for drilling dynamics while cleaning out cement. Recommendations for improvements from this trial test are planned to be implemented in future field tests.
Agile Field Development Planning: A Systems Approach
Authors: Ciccarelli John , McLachlan Duncan , Singh Himadri , Thomson Rob
Published: October 2018

It can take months, perhaps a year or two, to get through Front End Loading (FEL) stages with the current industry approaches. As the industry strives to be more efficient, faster to market in this lower for longer world, we need a different and much faster, lower risk approach that does not erode value. Multiple tools exist that allow subsurface/surface simulation integration and coupling, but these are cumbersome to configure and not appropriate for an early field development at the stage of pre-FEED (Front End Engineering and Design).

To meet this challenge, an agile approach to Field Development Planning (FDP) has been established. The approach is inspired by agile project management techniques and best practices that are currently used in the automotive, aerospace, construction, software development industries and lean start-ups. It is based on parallel sprints rather than the waterfall approaches to project management. Collaborative teams work on parallel deliverables to create a minimum viable product (MVP) and value drivers for further development are established quantifiably with an Analytic Hierarchy Process (AHP). The notion of a fully representative dynamic techno-economic model is presented. This model applies a multi-dependent system thinking approach, with dynamic integration of economic, reservoir, subsea, facilities and schedule data.

Two case studies are discussed where this approach was used to maximise economic benefits of the asset and accelerate the decision-making process during FEL stages: Identification of the best compression solution to optimise the economic outcome of production from a complex group of 350 wells intersecting different reservoirs. The result of this example was an 18-month acceleration of the decision process and 30% cost saving.Deciding whether the FEED should be oriented towards simultaneous or sequential production for the development of two marginal offshore satellite fields.

This presentation will be of interest to anyone looking to speed up the time to first oil/gas and reduce production costs on undeveloped or underdeveloped fields and bid more confidently on assets during licence rounds with less risk. It will also be of interest to those wanting to accelerate their decision-making process during FEL stages from months or years to weeks and allow decision makers to visualise and test inter-dependencies creatively with less cognitive bias.
Displacement Efficiency for Primary Cementing of Washout Sections in Highly Deviated Wells
Authors: Renteria Alondra , Maleki Amir , Frigaard Ian , Lund Bjornar , Taghipour Ali , Ytrehus Jan David
Published: October 2018

Anywhere between 0%-80% of cemented wells have integrity failures, suggesting both geological and operational factors. One way geology affects cementing is via irregular wellbores, e.g. washouts. Here we study the effects of washouts on mud removal in strongly inclined wellbores, experimentally and via 2-D computational simulations, with aim of identifying key control parameters.

Experiments were performed with 2 fluids with properties representative of drilling mud and cement (or spacer), displaced at constant flow rate through a 10 m long annular flow loop. A downstream "washout" section of the annulus had an enlarged outer diameter. Twenty-four conductivity probes tracked the arrival times of the displacing fluid by measuring the conductivity of fluids as they pass. The experimental matrix includes 8 experiments with 2 eccentricities (standoff = 1, 0.58), 4 angles of inclination and slightly variable rheology. The simulation study covered wider ranges of variables. The results of simulations and experiments agree qualitatively on the main effects, as shown in [7].

Here we extend the study using the 2D simulation to study the effects of washout length and diameter, for both concentric and eccentric wells, all oriented horizontally. The simulations provide detailed information on the evolution of the fluid-fluid interfaces as they pass through the washout, as well as information on the velocity fields and stresses. In any near-horizontal section there is a delicate balance of buoyancy and eccentricity influences, in both regular and irregular geometries. Under some circumstances an irregular section seems to have a positive stabilizing effect on the interface. However, this positive message is balanced practically by uncertainty of washout size and in-situ mud properties and the positive effects are not universal. We find that increasing the washout diameter always appears to decrease the displacemnt efficiency, for both concentric and eccentric annuli. Increasing the washout length is less clear in its effects. In all cases, the main risk from residual drilling mud in isolated washouts is that it can contaminate the cement slurry as it passes.
A General Purpose Model for Multiphase Compositional Flow Simulation
Authors: Wu Shuhong , Dong Jiangyan , Wang Baohua , Fan Tianyi , Li Hua
Published: October 2018

Reservoir simulation has come a long way since its birth in the 1950s and now is an important tool for reservoir engineers to predict oil and gas production and optimize reservoir management. In the past, many existing models were developed to simulate fluids with a specific fluid characterization such as black oil, compositional and thermal models. Today, the need for optimizing reservoir life with different recovery techniques and different fluid characterizations is urgent to fully evaluate oil and gas fields assets.

In this paper, a flexible general purpose model has been developed for multiphase isothermal or thermal compositional flow simulation in porous media, including formulations, phase behavior calculation, various numerical techniques. Based on general mass balance equations and energy balance equations, a mass variable set has been chosen for the generality for all types of fluids (black-oil, compositional and thermal) to ensure that each grid block has the same amount of primary unknowns and it is convenient for Jacobian matrix construction. The model decouples fluid and formulation from the rest of simulator and makes is possible to model different reservoir physics in one single simulator.

The model have tested and validated on various standard comparative benchmark problems like black-oil model, compositional model as well as large complex field cases with over one million grid blocks and an actual reservoir simulation. The test results show that the simulator is comparable with current commercial simulators in accuracy and speed. When different recovery techniques are used in a reservoir life cycle, the model is more efficient and accurate without the need of switching simulators. The generic and modular design architecture provides convenience for extensions of modeling additional flow processes and implementing new numerical solution methods. Developing a general purpose reservoir simulator is the main focus in state-of-the-art reservoir simulation research. The proposed general purpose model for multiphase compositional flow simulation in this paper is one step closer to the goal.
Rigless Intervention to Secure Internal Blowout IBO Monitoring Gas Wells Offshore of Brunei
Authors: Leong Azemi , Azizan Yusri , Yong Yee Tzen , Song Yan , Abd Rani Rudzaifi Adizamri , Jasni Mohd Majdi
Published: October 2018

Mature fields often include wells or platforms that require a plug and abandonment (P&A) job and decommissioning. Two high-pressure gas wells were identified in a field offshore Brunei that required a coiled tubing unit (CTU) intervention to secure them. The job was further complicated by high reservoir pressure in a tight formation, a small platform area, and no existing surface facility.

Because the flowline and pipeline equipment on the platform are not in service, a method was needed to take large volumes of returns. To overcome this challenge, an integrated operation was designed and planned that uses a complete catenary CTU and a pumping and flowback package with a mobile storage support vessel. The returns system will enable liquid (brine and spacer) and gas returns with pressures of up to 5,000 psi. The mobile storage support vessel enables the returns to be stored before disposal at an onshore facility.

Before killing the wells and pumping cement across the perforation, multiple tubing plugs must be removed. High tubing pressure indicated some communication to the reservoir; consequently, the plug removal strategy with coiled tubing (CT) must include risk mitigation to ensure that the plugs can be removed safely.

After all plugs were removed, the wells were successfully killed by using a 17 kPa/m (14.45 ppg) calcium chloride/calcium bromide (CaCl2/CaBr2) blend brine. The next operation was to spot cement across the perforation to a depth that is below where the tubing will be cut during the P&A process. The spacers and cement design must be tailored to avoid compatibility issues with the CaCl2/CaBr2 and the presence of carbon dioxide (CO2). The cement placement with CT is critical to prevent flash reaction with the kill fluid and to minimize the volume of contaminated cement. The cement was placed successfully and tested in accordance with the Brunei Shell Petroleum requirement.

The wells were safely secured and ready for the planned P&A process. These operations marked the first successful operation on high-pressure, tight gas wells with no surface facilities on the platform within a sensitive environment. The use of a mobile storage support vessel enabled the wells to be killed successfully. This approach demonstrates that a similar method and similar planning can be used to safely and economically perform future interventions.
Case Study Applied Machine Learning to Optimise PCP Completion Design in a CBM Field
Authors: Prosper Charles , West David
Published: October 2018

The key objective of multiple Coal Bed Methane (CBM) development operations is to determine cost effective methods to allow sustainable economic production and maximum reserves recovery. The cost of workovers as well as the associated deferred production may overwhelm the economic viability of the field. The primary reason for workovers is progressive cavity pump (PCP) system failures.

Here, we demonstrate the use of a machine learning framework that can be used to customise each workover configuration such that it optimises PCP run-life, respecting the well's heterogeneity and age. The framework can be generalised into three major parts: 1) converting the dynamic production data into a stationary surrogate model for the well; 2) the use of Gaussian process regression to create a function that estimates runlife; 3) an optimiser that will search the functional space to recommend the best completion design.

A telemetry and completion dataset for PCP run-lives from years 2014-2018 was obtained across the Surat and Bowen basins. After filtering data for completeness, 1499 PCPs remained in the cohort, of which, 895 failed during the observation period. A small portion of the original data was used as a test set.

Our work suggests that PCP run-life can be extended by taking a multivariate statistical approach to provide recommendations for customised completions and production strings per well that respect the wells’ geology and production history and thereby improve life of field economics.
Probabilistic SCAL Parameters for an Intermediate Wet Clastic Environment
Authors: Morrison Graeme , Taylor Ebony
Published: October 2018

In an era of automated workflow-assisted dynamic modelling, Special Core Analysis (SCAL) parameters require updating for each static realisation and evaluation at a quantifiable, probabilistic level-of-certainty. Additionally, SCAL data gaps combined with limited reliable SCAL data drive the need to establish trends and correlations from analogues.

SCAL parameters from analogue fields were selected and filtered by depositional environment and laboratory experiment type (centrifuge versus displacement). These analogue SCAL parameters were allocated to statistical bins defined by absolute permeability ranges. Statistical analysis of each SCAL parameter allocated to each permeability bin produced a probability distribution discretised by percentile. Multi-variable linear regression (MVLR) was then implemented to correlate each SCAL parameter, as the response variable, to input variables absolute permeability and percentile. SCAL correlations of reasonable to excellent quality were obtained.

The depositional environment was of second order influence in establishing these SCAL correlations. This was due to the selection of core plugs for laboratory analysis from layers of similar quality irrespective of the depositional environment, highlighting the need to select samples characterising a range of lithology and reservoir quality. Centrifuge experiments of water displacing gas were discarded as unreliable due to the compression of the gas phase by the experimental technique.

The multi-variable linear regression methodology enabled SCAL parameters to be determined as a function of both absolute permeability and probability. This approach should enable an automated implementation of SCAL parameters within each dynamic model realisation.
Reservoir Architecture Analysis of Delta Front and Its Control on Remaining Oil Distribution of S Oilfield in Bohai Bay Basin
Authors: Li Junfei , Liu Xueqi , Gao Zhennan , Shang Baobing , Xu Jing
Published: October 2018

After more than 20 years’ development, S oilfield has entered high water cut stage. The layer contradiction is prominent and the water flooding condition is complex, which result in the complex decentralized state of the remaining oil. In order to determine the remaining oil distribution to guide the comprehensive adjustment of the oilfield, the reservoir architecture analysis of delta front was conducted.

Based on the core, seismic data, dense well logging data and production performance data, the reservoir architecture of delta front in Dongying group is characterized with hierarchy process, model guidance and numerical simulation methods. In the paper, the distribution style of interlayers in single mouth bar is discussed. The distribution feature of the remaining oil under the control of interlayers is analyzed.

It shows that multiple main channels form continuous mouth bar complex and single mouth bar develops several accretions. Interlayers in single mouth bar express in two forms: the foreset type along the source direction and the arch type perpendicular to the source direction with a low angle from 0.4° to 1.0°. Along the source direction, remaining oil gathers inside accretions whose injection-production does not correspond under the control of interlayers. And the remaining oil is enriched at the front of accretion. In the vertical source direction, the remaining oil accumulates in the high part of accretions. Under the guidance of remaining oil distribution characteristics controlled by reservoir architecture, one horizontal well was deployed. The average output is more than 100m3/d and the water cut is under 30%, which indicates the effect of this reservoir architecture analysis work.

The successful implementation of the horizontal well demonstrates the vital function of the reservoir architecture research for this kind of mature oilfield. This will also be one promising research direct for the overall adjustment and remaining oil tapping.
A Novel Downhole Gas Separator in ESP Systems
Authors: Wang Qinghua , Liu Yonghui , Yang Junzheng , Cui Mingyue , Qi Dan
Published: October 2018

For Electrical Submersible Pump (ESP) systems in high-GLR wells, presence of gas inside ESP results in the degradation of hydraulic head. As a remedial tool to improve the ability of handling gas-liquid mixtures, Downhole Gas Separator (DGS) is of crucial importance. However, conventional DGS has limited capability in separating free gas and a maximum separating efficiency of 45%. It can't meet the field applications to a wider range of flow conditions and different pump models. Therefore, the paper proposed a solution to improve gas handling ability of DGS to expand its application.

Combining centrifugal separation method and gravity separation method, three-annular design was proposed to address the problem of two-stage separator with fairly long length. In the new design, a device is used to accelerate the fluid for higher velocity flowing into the annular between the spiral outer pipe and the central pipe. Then, the helical blades in the annular separate the gas-liquid mixture, leading gas attaching on the out wall of the central pipe and subsequently discharge into casing through the vent holes. The liquid attached on the inner wall of the spiral outer pipe flows reversal because of gravity. Afterwards, liquid is forced into the central pipe through the drainage holes and then flow into the ESP. In order to improve separating efficiency, the structure of helical blades, including distance and number of thread for centrifugal separator was then optimized by numerical simulation. In addition, an experimental study was conducted in different GLR and deviation. The experimental results show separating efficiency ranges between 88% and 96% while the conventional is under 60%. Furthermore, the separation efficiency decreases with the increasing of deviation, and maximum deviation of the new separator can be applied is 50°[1].

The novel DGS provide an economic solution for ESP application in gassy reservoir with low cost and power; since the new design greatly shorten the length of traditional two-stage separator.
A Review of Recent Advances in Cost-Effective Infrastructure System Design of the CO2 Distribution to CCS Injection Wells
Authors: Dashti Hossein , Underschultz Jim , Garnett Andrew , Honari Vahab , Sedaghat Mohammad , Rudolph Victor
Published: October 2018

CO2 transport from capture sources to storage sites is one of the leading parts of the carbon capture, and storage (CCS) infrastructure that needs to be optimized in order to reduce the capital, operating and maintenance (O&M) costs. This paper conducts a systematic overview of CO2 transport and identifies the knowledge gaps with a view for application to optimal CCS Hub design. The findings show that much research has been focused on the engineering and economic consequences in pure CO2 streams while in most real field studies the captured CO2 is accompanied with trace impurities that can affect the "intelligent" cost model's confidence to estimate CO2 pipeline costs. The impacts of different topographical conditions in current models on the economic pressure drop and inlet pressure is another challenge that has received little attention in the literature. Most cost-effective pipeline systems described in the literature, are based on the simple point-to-point design while the capture of CO2 from multiple sources and transport to multiple distributed CCS injection wells is an issue for the industrial-scale rollout of CCS. The lack of sufficient studies on the flow variations within CO2 networks is the last discussion in this research review. Further, there have been several cost models reported in the literature, and most of them are based on the costs of the natural gas pipeline infrastructure. However, the higher operating pressure of CO2 and the various impurities in CO2 streams from capture plant may require construction material specifications that will affect cost models. A systematic understanding of how CO2 pipelines contribute to CCS chain economics is still lacking. While many optimization challenges have been solved for natural gas pipeline networks, there are different thermodynamic behaviors for CO2 that require further optimization. The potential minor impurities that could occur in CO2 pipelines such as water (H2O), nitrogen (N2), oxygen (O2), hydrogen sulfide (H2S) and methane (CH4) can add complexity compared to the transport of natural gas.
The Lean Fluid Lifecycle: Optimizing Consumption and Waste in Hydraulic Fracturing Operations
Authors: Jukes Rachael
Published: October 2018

This paper presents a case study reviewing the systematic optimization of fluid transport, consumption and waste in large hydraulic fracturing development campaigns. With a focus on reducing consumption, re-thinking transport, and creating value from waste fluid through recycling and reuse, the methodology applied has resulted in very real gains in economic, environmental, social and safety outcomes. The objective of this case study is to provide practical information and guidance for planning, execution and ongoing optimization to not only reduce the footprint of hydraulic fracturing activities but also reduce cost.

By applying the methodology within this paper, the following was achieved over a 90 well development program: Fluid transport via trucking to wellsite virtually eliminated through use of the water production gathering network;Total fluid requirements reduced by 50%;Chemical costs reduced by 35%;Fluid disposal volume via trucking reduced by 95%; andFluid waste disposal costs reduced by 90%.

While the case study presented is based on a coal bed methane (CBM) development where between 3,000 to 6,000 barrels of clean fluid was required per well, some or all of the methodologies may be applied to shale and conventional markets. With trends in stimulation volumes within the United States shale plays increasing more than threefold in recent years to upwards of 160,000 barrels per well (Dunkel, M. R., 2017), it is the responsibility of the industry to ensure that further growth into Australian shale markets – such as in the Northern Territory – are managed sustainably. For optimal results, fluid logistics cannot be an afterthought in development planning left to the hydraulic fracturing operation, but a key consideration in the overall project strategy.
Vertical Minihole Creation and Fracturing Technology for Completing Unconventional Wells
Authors: Surjaatmadja Jim B. , Abass Hazim H.
Published: October 2018

The success of shale development has inspired new technologies to economize the extensive fracturing treatments necessary to complete extremely low permeability commercial wells. While bi-wing fractures are typically achieved during conventional fracture stimulation applications, it is often necessary to generate a complex fracturing network for most formation types encountered in very low permeability unconventional wells. Therefore, for source shale formations, the emphasis is on connectivity to natural fractures to establish an adequate stimulated reservoir volume (SRV).

This paper discusses a new approach where improved initial wellbore-to-formation connections can be achieved by creating extended large diameter vertical cavities from the lateral as an effective fracture initiation point. This provides improved connectivity to the stimulated reservoir network both during stimulation and production. Additionally, this paper discusses the unique mechanics of the new procedure to generate a large connected SRV (CSRV) in unconventional formations, the technique, and the resulting benefits in fracture stimulation of resource shales or in ultra low permeability sandstones or carbonates as well as coal reservoirs. This new approach is fairly easy to implement, can be applied with limited hydraulic horsepower availability, and the impact could be substantial.
Investigation of Partial Miscibility Between Gas Condensate PVT Samples and Oil Based Mud
Authors: Bon J. , Ortega P. A.
Published: October 2018

The measured PVT properties of gas condensate reservoir fluid samples collected while logging from wells drilled with Oil Based Mud (OBM) will often suffer due to contamination from the base oil. The objective of this work was to investigate the effects on reservoir fluid PVT properties of certain components dissolving preferentially into the gas stream and from the reservoir gas into the base oil.

Using a modified slim tube set-up, a reservoir gas was contaminated with base oil from an OBM. The two fluids interacted within a porous media under reservoir conditions by injecting the reservoir gas into the slim tube that had been pre-charged with base oil. After displacing all liquids, gas samples were collected again under reservoir conditions creating a batch of contaminated samples.

Using the results of compositional and PVT data obtained from contaminated samples at the back end of the slim tube and the original clean reservoir gas, a fully compositional numerical simulation model was created to simulate the experimental results.

During the experimental work, after extended flow of the reservoir gas through the modified slim tube we noticed that the reservoir gas was being produced leaner, indicating that the heavier components of the reservoir gas were staying on the porous media.

Using the compositional simulation model, we tested the sensitivities of conditions under which heavy end stripping of the gas condensate components may occur and how to obtain cleaner reservoir fluid samples faster from wireline formation testers in OBM drilled wells.

The modelling work indicates that when the reservoir gas and base oil are more miscible cleaner samples are obtained sooner.

Throughout this work we have been testing the idea that, if not completely miscible, the near wellbore region will retain an immobile phase of base oil and that this stationary fluid may hold back the heaviest components native to the reservoir gas. Furthermore, perhaps by altering the properties of the base oil, miscibility between the reservoir gas and base oil can be increased and improved samples obtained faster.
Practical Workflow to Estimate Expected Ultimate Recovery in a Fracture Stimulated Multi-Layered Tight Gas Reservoir: A Case Study from Big Lake Field
Authors: Guillen Falcon G. E.
Published: October 2018

A robust estimation of the Expected Ultimate Recovery (EUR) for fracture stimulated multi-layered tight gas wells, early in the production life of the wells, is the cornerstone for a meaningful project economic analysis, reserves classification and future field development plan, however, it actually presents significant challenges to reservoir engineers.

The complex flow dynamic of a tight gas reservoir causes that the direct application of the most commonly used reservoir engineering techniques to characterize Original Gas In Place (OGIP) such as Static Material Balance (P/Z vs Gp plot) and Flowing Material Balance (FMB), and EUR estimation such as Decline Curve Analysis (DCA) can only provide reliable results within an acceptable level of uncertainty when significant production decline data is available (minimum 6 to 9 years of production history in the case of Big Lake wells). This makes early predictions of future production decline behavior hence EUR highly uncertain, sometimes even unrealistic and very subjective to the analyst, with significant potential impacts.

The objective of this work is to present a practical workflow that provides suitable constraints to be applied to the otherwise poorly constrained DCA technique for EUR estimation by making appropriate adjustments to the results obtained from the standard reservoir engineering techniques when applied to the early production decline data of multi-layered tight gas wells, based on relevant correlations from a detailed production and reservoir analysis of numerous field cases from the Big Lake Field in the Cooper Basin.

Specifically, the study illustrates: (1) that the OGIP from P/Z determined early in the production life of a well, although using imperfect Build-Up pressures (static pressure values taken at the well which are still building pressure due to reservoir characteristics and sampling period), can be reasonably corrected to better represent the long term connected OGIP to the well, through a correlation between P/Z and FMB analysis on existing wells. (2) The integration of Production Logging Tests (PLT) data and petrophysical properties provides important inputs in order to better characterize the vertical heterogeneity of the reservoirs and simulate the aggregate Recovery Factor (RF) in a multi-layer production scenario. (3) A more constrained multi-segment DCA, constructed honoring the results from point 1 and 2 better represents (within 6% deviation) the production forecast of over 40 wells in the Big Lake Field after a year and half of additional production and it is expected to be a close approximation of the EUR of the wells (assuming current operating conditions).
Effect of Low Pumping Rate on Mud Displacement Efficiency and Pumping Pressure During Cementing of Oil Wells
Authors: Tcibulskii Mikhail , Akhmetov Marsel
Published: October 2018

The Vostochno-Messoyakhskoe field is the northernmost active continental field in the Russian Federation (Fig. 1). This field is located 250 km from the Arctic Circle, in the arctic climatic zone. Full production drilling only began in 2015 because of the field's geological complexity and lack of transportation structure. Weather conditions, such as strong winds and extremely low temperatures, can be hazardous to personnel and equipment. Additionally, this oil field has permafrost zones (400m from the surface) and low formation temperatures at the production zone. Also, because of permafrost zones, there is a high risk of thawing the wellhead formation. These conditions significantly affect which technologies can be applied during drilling and completion of the wells. Therefore, special cement designs are necessary to help reduce risks associated with low temperatures and permafrost zones in the Vostochno-Messoyakhskoe field.

Production is further complicated by a gas layer at 720 to 820m true vertical depth (TVD) and high formation pore pressure. This can make the cement operations with the production casings difficult. While the TVD of the casing landing is not relatively deep, the measured depth (MD) in extended reach drilling (ERD) wells is significant (Fig. 2). ERD wells can challenge cement displacement efficiency (Sabins, 1990). Mud removal efficiency may not be enough to create a high-quality cement barrier and isolate formations from gas migration. Poor mud removal can affect future life of the wells and crude oil production. To perform remedial jobs, it is necessary to stop production for several days. Due to experience in performing remedial jobs in the Messoyakhskoe field, it is usually necessary to perform a few attempts of the remedial cementing operation to reach positive results. Therefore, the operator decided to utilize hydraulic packers to create a second barrier between the surface and production casings to help prevent gas migration to the surface, save time associated with remedial operations, and extend the life of future wells.
An Investigation into the Benefits of Combined Polymer-Low Salinity Waterflooding
Authors: Santo Asmoro , Muggeridge Ann
Published: October 2018

Polymer flooding and low salinity waterflooding are two different but potentially complementary Enhanced Oil Recovery (EOR) techniques. Polymer flooding improves fractional flow and sweep efficiency by improving the mobility ratio for the displacement. Low salinity waterflooding improves pore scale displacement efficiency by changing the wettability of the reservoir rocks toward more water-wet. Reduced salinity water is often used in polymer injection to reduce hydrolysis however the water salinity in this case is typically higher than that needed to obtain a true low salinity effect. This paper describes the outcomes of a systematic study into the potential benefits of combined polymer-low salinity waterflooding versus polymer-high salinity waterflooding, polymer-reduced salinity waterflooding and conventional waterflooding.

Numerical simulation, validated against analytical solutions, was used to evaluate the relative performance of these processes. The impacts of layering and reservoir heterogeneity were investigated using two-dimensional (2D) and three-dimensional (3D) reservoir models. Sensitivity studies of injected water salinity and the start time of injection were carried out in each of these models. Outcomes were compared against the recoveries and water cuts predicted using a one-dimensional (1D) analytic solution for the EOR processes to evaluate the impact of sweep versus displacement efficiency on incremental oil recovery and water cut.

Combined polymer-low salinity waterflooding shows an improvement in recovery and reduction in water cut compared with the other EOR processes in all cases. We show this is partly due to improving the fractional flow (increasing shock front saturation) but is also due to both the leading and trailing shock fronts in polymer-low salinity waterflooding being more stable than in the other EOR processes, reducing the possibility of viscous finger growth and thus increasing performance. The highest incremental oil recovery is observed when the injected water salinity in the combined polymer-low salinity waterflooding is reduced to below the low salinity threshold. It is clearly beneficial to reduce the water salinity to this low level rather than just to a salinity where hydrolysis is prevented. The injection of the combined EOR technique in tertiary mode, particularly at 75% water cut after performing high salinity waterflooding, exhibits an incremental oil recovery of between 15 and 42% and a reduction in water cut of between 11 and 48% at 1.0 pore volume injected (PVI).

This is the first systematic investigation into the performance of combined polymer-low salinity waterflooding compared with conventional waterflooding, low salinity waterflooding, and polymer flooding with reduced salinity water. It provides a clear insight into the benefits of combined EOR process justifying the need for field scale pilots and further laboratory studies.
A Novel Ultra-Low Interfacial Tension Nanofluid for Enhanced Oil Recovery in Super-Low Permeability Reservoirs
Authors: Xu Derong , Bai Baojun , Meng Ziyu , Zhou Qiong , Li Zhe , Lu Yao , Wu Hairong , Hou Jirui , Kang Wanli
Published: October 2018

The exploration and development of super-low permeability reservoirs have become a global focus in recent years. However, conventional flooding systems commonly face problems of high injection pressure and poor displacement efficiency in super-low permeability reservoirs. Thus, it is imperative to find new flooding agents that tackle such problems.

In this study, a novel ultra-low interfacial tension (IFT) nanofluid was formulated, consisting of surfactants to achieve ultra-low IFT and silica nanoparticles to reduce injection pressure. The compatibility test between the surfactants and silica nanoparticles in 10,000 mg/L NaCl solution at 90 °C was conducted to ensure their adaption to harsh reservoir conditions. Also, the effects of silica nanoparticles on the IFT and emulsion stability of the surfactant solution as well as wettability of reservoir rock were evaluated to determine the optimum concentration of nanoparticles. Finally, oil displacement efficiency of the nanofluid was assessed and compared from respective nanofluid flooding, surfactant flooding and surfactant-free nanofluid flooding.

The compatibility results showed that the ultra-low IFT surfactant solution with silica nanoparticles remained clear and stable at 90 °C for one month. The surfactant solution can effectively emulsify oil, and the stability of the oil emulsion could be further improved in the presence of silica nanoparticles. In addition, the solution could achieve lower IFT at both low and high temperature with the addition of 0.01% silica nanoparticles. The silica nanoparticles could effectively alter the wettability of the rock, making it become more water-wet with increasing silica nanoparticle concentration. The displacement experiments through 0.2–0.3 mD tight cores indicated that the enhanced oil recovery could reach 21.12%OOIP by the nanofluid flooding after water flooding, higher than that of surfactant flooding (18.84% OOIP), and much higher than that of surfactant-free nanofluid flooding (3.48% OOIP). Moreover, the injection pressure difference was able to decrease nearly 50% after nanofluid injection in comparison with the occurrence of an increase in pressure along the surfactant solution injection. Thus, the combined surfactant and nanoparticles behaved excellent synergistic effect.

The newly formulated surfactant based silica nanofluids can efficiently enhance oil recovery in comparison with water flooding, and significantly lower the injection pressure compared with the surfactant flooding. This work lays the foundation for the application of ultralow IFT nanofluid flooding technology in super-low permeability reservoirs.