bluuebunny/crossref_metadata_2025 huggingface dataset:
The Impact of Surfactant Imbibition and Adsorption for Improving Oil Recovery in the Wolfcamp and Eagle Ford Reservoirs
Authors: Alvarez J. O. , Saputra I. W. , Schechter D. S.
Published: October 2018

Improving oil recovery from unconventional liquid reservoirs (ULRs) is a major challenge, and knowledge of recovery mechanisms and the interaction of completion-fluid additives with the rock is fundamental in tackling the problem. Fracture-treatment performance and consequent oil recovery can be improved by adding surfactants to stimulation fluids to promote imbibition by wettability alteration and moderate interfacial-tension (IFT) reduction. Also, the extent of surfactant adsorption on the ULR surface during the imbibition of completion fluids is a key factor to consider when designing fracture jobs. The experimental and modeling work presented in this paper focuses on the effectiveness of surfactant additives for improving oil recovery in Wolfcamp and Eagle Ford reservoirs, as well as the extent of surfactant loss by adsorption during the imbibition of surfactant-laden completion fluid. Original rock wettability is determined by contact angle (CA) and zeta potential. Then, distinct types of surfactants—anionic, anionic/nonionic, and cationic—are evaluated to gauge their effectiveness in altering wettability and IFT. Moreover, surfactant-adsorption measurements are performed using ultraviolet/visible (UV/Vis) spectroscopy. Next, the potential for improving oil recovery using surfactant additives in ultralow-permeability Wolfcamp and Eagle Ford shale cores is investigated by spontaneous-imbibition experiments, and computed-tomography (CT) methods are used to determine fluid imbibition in real time. Finally, laboratory data are used in numerical simulations to model laboratory results and to upscale these findings to field scale. The results showed that aqueous solutions with surfactants altered rock wettability from oil-wet and intermediate-wet to water-wet and reduced IFT to moderately low values. In addition, cationic surfactant presented the highest adsorption capacity following a Langmuir-type adsorption profile. Spontaneous-imbibition results showed that aqueous solutions with surfactants had higher imbibition, and were better at recovering oil from shale core compared with water without surfactants, which agrees qualitatively with wettability and IFT alteration. However, rock lithology and surfactant type played a key role in adsorption capacity and oil recovery. Our upscaling result showed that, compared with a well that is not treated with surfactant, a 24% increase in the initial peak oil rate and an 8% increase in the 3-year cumulative oil production were observed. For the results obtained, we can conclude that the addition of surfactants to completion fluids can improve oil recovery by wettability alteration and IFT reduction, maximizing well performance after stimulation from Wolfcamp and Eagle Ford unconventional reservoirs.
Monitoring Water Flood Front Movement by Propagating High Frequency Pulses Through Subsurface Transmission Lines
Authors: Felix Servin Jesus Manuel
Published: October 2018

This manuscript describes a novel approach to monitor water flood front movement using Proximity Sensing in conjunction with contrast agents. Our technique exploits the presence of resistive layers between reservoirs, which act as a transmission line for electromagnetic signals, to achieve increased propagation range. This work focuses on numerical simulations to evaluate the potential of this approach to monitor water movement in the reservoir under different conditions.

A series of 2D axisymmetric numerical simulations were conducted to assess the potential of Proximity Sensing to monitor moving fronts of labeled brine as well as to detect isolated pockets of brine labeled with contrast agents. The study was conducted using layered models that resemble a resistive seal bounded by reservoirs saturated with brine or brine and contrast agents. The effect of magnetic permeability (μ) on signal travel time and amplitude is reported and compared to the effect of electric permittivity (ε).

The results show that Proximity Sensing is a suitable technique to detect changes in the μ of reservoirs adjacent to resistive seals. Therefore, our approach can be used in combination with contrast agents, such as Magnetic NanoMappers, to monitor water flood front movement in the reservoir. In addition, this technique can be used to detect isolated pockets of labeled brine, which suggests that injection of slugs of labeled water would be enough for field applications. The observed effect of μ on signal travel time is similar to the trend observed when the electric permittivity of the bounding reservoirs is changed. A significant difference is that increasing μ of the bounding reservoirs appears to reduce signal amplitude while increasing ε has the opposite effect. This result was unexpected and requires further simulations and experimentation to validate this behavior.

Proximity Sensing offers a novel approach to address the challenge of electromagnetic propagation in conductive media and paves the way for the development of refined techniques that provide reservoir saturation and water flood front monitoring capabilities with greater resolution.
Multi-Scale Digital Rock Quantitative Evaluation Technology on Complex Reservoirs
Authors: Jin Xu , Yu Chen , Wang Xiaoqi , Liu Xiaodan , Li Jianming , Jiao Hang , Su Ling
Published: October 2018

High heterogeneity and small pore throat characterize the mineral compositions of complex reservoirs. The evaluation of the effectiveness of reservoir space, the detailed evaluation of the rock structure, and the evaluation of fluid occurrence and migration all determine the possibility of oil and gas exploration within complex reservoirs. The technologies and workflows used for the multi-scale digital rock evaluation of complex reservoirs analyze the reservoir space (i.e., the pore throat and fractures), the rock structure (i.e., mineral and organic matter), and fluid characteristics. For the reservoir space, two-dimensional large-area analysis is sufficient to evaluate heterogeneity and multi-scale selection across 6–7 orders of magnitude. Three-dimensional space distributions of pore throat and fractures are precisely depicted through a combination of multi-scale CT and FIB-SEM. The developing agent facilitates the analysis of the micro-pore connectivity effectively. For the solid components, a quantitative evaluation of mineral composition and distribution is possible using Qemscan, and organic matter morphology and distribution are quantitatively assessed using the three-dimensional FIB-SEM. To characterize the fluid, charging effects may aid in the identification and characterization of residual, organic fluid traces. We perform the physical modeling of shale oil occurrence and migration by using nano materials that have adjustable pore sizes, adjustable wettability, and adjustable surface microstructure to understand the impact that each factor has on shale oil occurrence and the lowest pore sizes in which fluid can migrate. We use molecular simulations to observe oil and gas aggregation mechanisms and the diffusion potential in inorganic and organic nano pores. To supplement the conventional reservoir analysis, multi-scale digital rock evaluation, and its specific applications, provide technical proof for effective complex reservoir assessment, including shale oil and gas reservoirs, tight sandstone oil and gas reservoirs, and deep oil and gas reservoirs, as well as a quantitative oil-gas probability evaluation.
Impact of Laboratory Testing Variability in Fracture Conductivity for Stimulation Effectiveness in Permian Deep Coal Source Rocks, Cooper Basin, South Australia
Authors: Fraser Samuel A. , Johnson Jr. Raymond L.
Published: October 2018

Hydraulic fracture stimulation of low permeability source rock-reservoirs is increasing in the industry and low-permeability, deeply buried coals, "Deep Coals," represent an underdeveloped resource in the Cooper Basin of South Australia. Numerous treatments have been performed with overall technical success but varied productivity. Thus, it was important to understand the potential hydraulic fracture conductivity in the Permian Deep Coal play by evaluating the key treatment variables affecting post-stimulation results.

Proppant conductivity tests were conducted on samples from two preserved Deep Coal cores of differing thermal maturity under laboratory conditions, replicating reservoir conditions. Varying concentrations and mesh sizes of lightweight ceramic (LWP) and sand proppants were tested at 250°F. All tests were subject to closure stresses observed in the field, ranging from 2,000 psi to 10,000 psi, using representative hydraulic fracturing fluids. Results revealed a significant conductivity difference between the two coal thermal ranks due to variation in mechanical properties

Varying proppant concentration tests revealed that effective conductivity at higher stresses occurs within a narrow window. This window is a balance between insufficiently low concentration resulting in significant conductivity loss, and excessive, non-linear conductivity gains in higher concentrations. Results from these studies are integrated into a hydraulic fracture and reservoir stimulation modelling software to up-scale the observed results versus the laboratory data. Finally, laboratory results helped explain trends for success in stimulation design based on observed post-frac, flow rates.
An Experimental Study of a Novel Parallel Pipe Separator Design for Subsea Oil-Water Bulk Separation
Authors: Skjefstad Håvard Slettahjell , Stanko Milan
Published: October 2018

As oil fields mature, the produced water content of the production stream will often increase over time, and produced water management will eventually become a bottleneck in production. Subsea separation of produced water enables prolonged lifetime of brown field installations, increased recovery rates and more energy efficient production. In addition, implementation of subsea water separation will also enable future tie-ins to existing facilities, and reduce the need for new and expensive transport lines. Existing installed subsea produced water bulk separator technologies are limited to gravity and compact gravity vessels, such as Troll and Tordis, and the Marlim pipe separator. These are large installations, which are costly to manufacture, transport and install. In addition, the gravity and compact gravity vessels are not suited for deep-water installations, and there is a need for novel solutions to both reduce the weight and size of bulk water separators, making the technology more attractive for new business cases.

In order to investigate improved subsea bulk water separation technologies, a multiphase oil-water test loop has been developed at the Norwegian University of Science and Technology (NTNU). Facility test fluids are ExxsolD60 and distilled water with wt%3.4 NaCl. In this paper, a new separator design, utilizing multiple parallel pipes will be presented. The design allows reduction of required wall thickness at large water depths, shorter residence times and hence a shorter separator length compared to traditional gravity based technologies. Initial performance data of a constructed medium scale prototype will be reported, including separation efficiency estimations over a range of flow rates, water cuts (WC) and water extraction rates (ER). Tested flow rates vary from 250L/min to 750L/min at 30%, 50% and 70% WC. Water extraction rates are varied from 50% to 100% of the inlet water rate.

Based on this initial test campaign, the concept proves promising, displaying good separation efficiencies (>98%) for both water continuous and oil continuous inlet flows at moderate flow velocities. At higher flow rates, performance decreases, and water extraction rates must be limited in order to maintain high efficiencies. Photos of flow conditions at the water outlet are included, providing a visualization of the occurring two-phase flow phenomena inside the separator.

The presented concept adds to an expanding portfolio of proposed subsea separation solutions, and displays a new way of utilizing parallel pipes to achieve oil-water bulk separation.
Discrete Net-to-Gross Truncated Gaussian Simulation: An Alternative Modelling Approach for CSG Unconventional Reservoirs, Bowen Basin, Eastern Australia
Authors: Rattazzi Simone , Hansen Alan
Published: October 2018

Building a representative static model for predicting and monitoring performance of coal seam gas fields presents several complex and unique challenges. The individual reservoirs possess very different coal architectures, often with highly complex seam splitting, amalgamating and structural deformation. The objective was to develop an alternative approach which honoured log and core data capturing both the lateral heterogeneity and the vertical signature of the Bowen Basin coals, Central Queensland.

In some areas of the Bowen Basin, coals can be thick and laterally continuous; picking the top and base of each seam works well in small models with homogeneous coals. As seam geometries begin to increase in complexity and coals become more heterogeneous in nature with thinner seams in multiple packages, then a net-to-gross (NTG) approach is often more appropriate. Each method has its merits. The former approach describes the reservoir architecture but implies a certain degree of confidence in coal correlation; in a vast field with complex seam splitting and merging with abundant drilling data, it may not be a practical technique. The later method (NTG) disregards coal seam architecture and reservoir connectivity.

The proposed workflow is designed to take advantage of both NTG characterization and facies modelling technique using a combined hybrid approach. The process is operating on a relatively coarse layered chronostratigraphic framework in which coal is captured as contiguous discrete-NTG "facies". The utilization of the Truncated Gaussian model ensures the contiguity of facies and mimics transitions between coals and carbonaceous mudstones (or other transitional interburdens). With the adoption of facies vertical proportion trends we are able to replicate a similar coal seam signature laterally away from the well bore. The definition of a categorical coal model allows the proper scaling of seams with different coal quality characteristics.

With the successful geocellular model re-construction of two historical Coal Seam Gas (CSG) fields in the Bowen Basin, the discrete-NTG Truncated Gaussian Simulation approach has proven to be a valid alternative CSG modelling technique.
Application of Managed Pressure Drilling on a Semisubmersible Tender-Assisted Rig to Address Drilling Challenges in HPHT Gas Condensate Wells, Offshore Vietnam
Authors: Dalgit Singh Harpreet Kaur , Ta Quoc Bao , Chai Yong Tan , Khanh Do Van , Cuong Nguyen Xuan , Tung Hoang Thanh , Nam Truong Hoai , Hai Ngo Huu , Tuan Dang Anh , Bao Trinh Ngoc , Hung Tran Nam , Cuong Nguyen Pham
Published: October 2018

High-pressure, high-temperature (HP/HT) environments often present kick and losses scenarios. Bien Dong POC Well-1 serves as an example of such scenarios with a very narrow-pressure operating window. Operational pressure challenges prohibited achieving the objectives.

While drilling the Bien Dong Well-1, the well encountered ballooning issues, high pore pressures, and a narrow window. As part of remedial actions when drilling Bien Dong Well-2 & Well-3, the Bien Dong POC drilling team decided to deploy MPD technology with constant bottomhole pressure and early kick-loss detection capabilities.

By applying MPD techniques, the team drilled the 12-1/4-in. hole section with the lowest possible mud weight to accommodate the narrow drilling window. Drilling the well sections to total depth (TD) took only 10 days in Well-2 and 14 days in Well-3. MPD also allowed stripping out of the hole with surface backpressure (SBP) instead of pumping out of the hole to minimize swab once in shoe, which reduced trips for considerable rig-time savings.

The wells were drilled using MPD technology on a semisubmersible tender-assisted rig. A comprehensive rig survey was conducted during the planning phase of rig construction. The survey outlined the permanent installation of the MPD system, including an automated MPD choke manifold and docking-station rotating control device (RCD). The MPD equipment was integrated into the rig on a flexible plug-and-play basis to enable easy rig up and rig down. The integration also enabled moving the equipment between wells when the rig skids and during the MPD operation. The success of MPD operations came through cooperation with team members, experience from lessons learned, and excellence in rig crew performance on well after well.

This paper will discuss how MPD technology led to campaign improvements and cost savings throughout Bien Dong Well-2 and Well-3.
Brittleness Index Prediction via Well Logs and Reservoir Classification Based on Brittleness
Authors: Feng Cheng , Deng Xili , Yin Wen , Wang Zhenlin , Mao Zhiqiang
Published: October 2018

Tight oil reservoirs need fracturing to obtain industrial productivity, and brittleness of rock has an important effect on fracturing. For oil reservoirs of the Permian Lucaogou Formation in Jimusar Sag of Junggar Basin, in order to predict brittleness index accurately, 19 typical tight oil core samples were selected and the related parameters of petrophysics and rock mechanics were measured at first, it is found that the static and dynamic brittleness indices vary greatly. Then, based on the static and dynamic experimental results of core samples and previous research results, the ratio of static and dynamic brittleness indices is constructed, it has a well correlation with porosity and clay content. Hence, according to the porosity and clay content correction, the static and dynamic conversion model of brittleness indices is built. The predicted results of the model are in good agreement with the experimental results. Then, on the basis of the composition, structure and deformation mechanism, the reservoirs are divided into three types via rock brittleness. The stress-strain curves of good, poor and moderate brittleness reservoirs are respectively linear, concave and "S". The static brittleness index-Poisson's ratio cross plot is built to classify the reservoirs. When the static brittleness index is greater than 85 and Poisson's ratio is less than 0.2, the reservoir shows good brittleness. When the static brittleness index is less than 40 and Poisson's ratio is greater than 0.24, the reservoir shows poor brittleness, and when the static brittleness index and Poisson's ratio are between them, the reservoir shows moderate brittleness. Finally, the static and dynamic brittleness index conversion model and reservoir classification standard are applied to formation evaluation in the study area, showing good application results. The research results are of guiding significance for the conversion of static and dynamic parameters of tight oil reservoirs, the selection of fracturing layers and fracturing operation schemes.
Geomechanics in Unconventional Reservoir: A New Approach to Drilling Integrating Advanced Acoustic Measurements and Formation Evaluation
Authors: Chatterjee Chandreyi , Reyes Allan , Lujan Violeta , Majumdar Chandan , Prasad Kanchan , Kumar Arvind
Published: October 2018

The Spraberry Trend oil field produces from a single enormous sand interbedded with shales, and typically pinch-out up dip. Being deposited in submarine channel systems and their associated fans, the sands are with very low porosity and permeability, both of which impede oil recovery. Oil has accumulated in stratigraphic traps, migrating upward from source rocks until find impermeable barriers. However, the natural fractures further complicated the hydrocarbon flow and pose drilling challenges in this field. A client has planned to drill deviated wells in Spraberry Trend area. They aimed to drill the wells with less drilling issues and Non-Productive Time. Wellbore instabilities and mud losses are more than in all wells drilled in Permian Basin and more specific in the prolific and acclaimed Midland Basin. Those drilling events are crucial to defining if the well will reach the goals and plans developed by geoscientists, drillers, and petroleum engineers. Decisions like casing points, open hole intervals, kick-off-points, curve sections, and finally landing points are very impacted if wellbore instabilities are present and this management is difficult to mitigate. To boost the drilling campaign, it was important to take control of the borehole problems and it was achieving through mud weight optimization. The laminated reservoir showed that isotropic stress model would not give correct stress parameters. Thus, a new workflow is being inherited to cogitate TIV (transverse isotropy vertical) stress model for wellbore stability analysis. TIV anisotropy analysis was performed on a representative vertical well using advanced acoustic measurements and the model was calibrated with post-drill events. This calibrated model gives the stable mud weight window for four planned laterals. This paper will highlight how a geomechanics-based approach, integrating advanced acoustic measurements, has significantly improved drilling rates by reducing drilling-related problems. The wells were drilled keeping the mud weight at the lower limit of the stable mud weight window. This led to faster drilling with an average rate of 1,300 ft/day. Reduction in wellbore instability issues has led to considerable reduction in time spent on reaming, mud circulation, cleaning tight spots, etc. This effectively reduced Non-Productive-Time and rig cost. Wellbore stability analysis incorporating anisotropic stress from advanced acoustic measurements has helped most right mud weight estimation and thereby drilling the wells at a faster rate in the unconventional reservoirs.
Novel Eco-Friendly Cationic Surfactant for Improving Oil Recovery from Carbonate Reservoirs
Authors: Valluri Manoj Kumar , Cain Robert , Lalgudi Ramanathan
Published: October 2018

Cationic surfactants have been proven to be highly effective in improving oil recovery in carbonate reservoirs with low surfactant loss due to adsorption. However, toxicity concerns and the cost of formulation have impeded their widespread usage in the oil and gas industry. Our study focuses on developing an economic and environmentally friendly solution to this challenge.

Soybean oil was used as the raw material to synthesize a surfactant that had 3 cationic sites. The resulting formulation, in conjunction with an ethanol co-solvent, was tested for emulsion and rock-fluid behavior with dolomitic reservoir rocks and oil sampled from a producing well in Morrow County, Ohio. Interfacial tension (IFT) and contact angle measurements were conducted to characterize rock-fluid behavior of the surfactant. Estrogenic and anti-estrogenic activity were evaluated to help understand its environmental impact. Finally, oil recovery was measured using spontaneous imbibition tests and the results were compared to those obtained using cationic and anionic surfactants supplied by a commercial vendor. All the tests were conducted at standard atmospheric conditions except the imbibition studies, which were conducted at reservoir temperature.

Our soy-based surfactant reduced the IFT by 60% and changed wettability from oil-wet to water-wet at concentrations lower than 3 gpt. No estrogenic or anti-estrogenic activity was detected for the surfactant at very high testing concentrations. The soy-based surfactant outperformed both the commercial anionic and cationic surfactants in imbibition tests recovering 35% of the oil originally in place (OOIP) inside the rock while the commercial cationic and anionic surfactants recovered 27% and 18% of OOIP, respectively.

These encouraging results suggest that our soy-based surfactant has the potential to provide cheap and eco-friendly solutions for improving oil recovery from tight carbonate reservoirs in addition to other potential near-wellbore performance enhancements that are currently being investigated. We believe this novel additive has the potential to solve oil recovery and near-wellbore issues at a lower cost to the operator and lesser impact on the environment compared to the products in use today.
Sand Conglomeration Trial as an Alternative to Sand Control: Case Study from Mahakam Delta, Indonesia
Authors: Styward Boris , Wijaya Ryan , Manalu Dasa , Wahyudhi Fransiskus , Setiawan Thomas , Dading Albert Malvin , Rizal Muhdi , Widarena Tri Maharika , Lukman Geraldie , Primasari Indah , Merati Putu Astari , Hezmela Rizka , Fuad Muhammad , Nwafor Chidi , Hai Liu , Singh Pratyush
Published: October 2018

Pertamina Hulu Energi operates numerous wells that produce gas from unconsolidated, tight sands in the Mahakam Delta. The company maintains a zero-sand production policy as its surface facilities are not designed to handle sand. If sand is produced, the wells are choked back, thus impairing the overall field production. To fix sand and fines in place, the primary sand control method used has been multizone single-trip gravel packing, sometimes in conjunction with sand consolidation or ceramic screen for noneconomic zones. However, the current state of the Tunu shallow portfolio renders sand consolidation infeasible, as more than 50% of the remaining reservoirs are either low-stakes (i.e. not economical) or are located in low-permeability zones. Against this backdrop, sand conglomeration is being considered as an alternative solution to produce the remaining reservoirs. A trial has been conducted to assess the feasibility of using sand conglomeration technology as an alternative to sand consolidation in the Mahakam Delta, the results of which will be reviewed in this paper.
An Integrated Cement Design and Evaluation to Reduce Downhole Sanding Risk
Authors: Cadogan Paul , Seth Kapil , Crabtree Richard , Beales Vincent , Alsayed Ayssar , Cheong Boon
Published: October 2018

As subsea completion and tie-back development plans become more plentiful, the impact of sand failure on production often severely impacts the economics of a gas field. The integrity of downhole, subsea and facility equipment may be compromised due to excessive sand production which can potentially lead to catastrophic failure. In cased and perforated sand-face completions, good cement sheath coverage across the casing can act as the main defense against excessive sand production. An integrated approach involving cement design, execution and subsequent evaluation is therefore critical to minimise sand production during the life of the well.

In this paper, we outline the evolution of the process of cement design, placement and evaluation used in a multi-well development campaign by an operator to achieve quality cement placement across the entire well length of the sub-horizontal wells.

At the commencement of the drilling campaign, perforation intervals were initially limited due to the combination of high levels of sanding risk and interpreted cement log. To limit unperforated sections, a dual pronged approach was instigated looking at both cement design and operations, and cement bond log evaluation. As the campaign progressed, both elements were improved leading to an overall improvement with respect to perforation length. Challenges overcome included lost circulation in fractured formation, poor mud removal in extended horizontal casing, gas migration into the cement sheath, the presence of micro annuli by the loss of acoustic coupling due to oil-wet casing and test pressure applied between cementing operations and evaluation.

In this paper, the entire cementing program design, placement and evaluation workflow will be explained with specific examples from the field development. Special focus will be given to the evaluation of the cement using state-of-the-art high-resolution wireline technology leading to a reduction in interpretation uncertainty through advanced workflows. Finally, examples will be provided where the inputs from the logs were integrated with both drilling and petrophysical data to evaluate the sanding propensity, thus allowing the operator to confidently perforate high-risk zones and ultimately improving well productivity.
Effect of Gas Injection Pressure on the Performance of CO2-Assisted Gravity Drainage Process in Heterogeneous Clastic Reservoirs
Authors: Al-Mudhafar Watheq J. , Rao Dandina N.
Published: October 2018

Many simulation studies have been conducted to investigate the effects of various factors on the Gas-Assisted Gravity Drainage (GAGD) process performance. These factors are controllable to constrain the amount of injected gas and produced oil in the vertical injection and horizontal production wells. One of the most recent simulation studies investigated the effects of six controllable factors: maximum oil production, minimum bottom hole pressure, and maximum water cut in the production wells along with maximum gas injection rate and maximum injection pressure in the injection wells. From that study, it has been concluded that the maximum gas injection pressure in vertical injectors has the highest effect on the performance of GAGD process. In this paper, an extensive simulation study was implemented to further evaluate how is dominant the maximum gas injection pressure to enhance the recovery of bypassed oil through the GAGD process.

Similar to the aforementioned recent study, the current simulation was carried out on the heterogeneous clastic reservoir (main pay) in the South Rumaila oil field, located in Iraq. The EOS-compositional reservoir flow simulation was adopted to evaluate the effectiveness of CO2–GAGD process under different periodic gas injection pressure levels. Design of Experiments and proxy modeling were adopted to obtain the optimal future oil recovery through changing the pressure in an annual basis. Various what–if–scenarios (simulation runs) were created by the Latin Hypercube Sampling and evaluated by the compositional simulation to find the optimal oil recovery. In the optimization process, the purpose was to search for the optimal future oil recovery by optimizing the levels of periodic gas injection pressure. The optimal cumulative oil production, by the end of 10-year prediction period, reached 4.838 MMMSTB of oil production, while the recent optimal GAGD process resulted to obtain 4.6039 MMMSTB of oil production. Therefore, the current optimization approach has led to increasing the oil recovery by 234.1 million barrels.
Lost Time Analysis of Queensland Coal Seam Gas Drilling Data and Where Next for Improvement?
Authors: Rodger Iain , Garnett Andrew
Published: October 2018

Due to the high number of wells required, drilling costs are a significant factor for coal seam gas developments. In order to improve drilling performance (and reduce associated costs) current performance should be analysed to identify areas with potential for improvement. This study makes use of a framework based on the best composite time (BCT) to assess the performance of wells drilled in Queensland, Australia in an example period in 2014-15.

Data recorded by Pason electronic drilling recorders at 970 wells was made available, along with end-of-day reports for 370 of these wells. Scripts written in the Python programming language were implemented to break the 8½ in. drilling stage down into depth sections and automatically generate a best composite time model for each field in the study. Individual well data was compared to this benchmark allowing the drilling performance to be compared to other wells in the same field, and identified removable time was classified as either invisible lost time (ILT) or non-productive time (NPT). In total over 4500 hours, or approximately 49.5% of the total 8½ in. drilling time, was identified as removable time across 828 wells when compared to field specific BCTs.

Causes of ILT and NPT were identified by analysing both numerical data and textual data in daily reports. There is a clear separation in key drilling parametes between the best and worst performing wells. ILT while on bottom correlated with lower recorded RPM, while ILT connecting was associated with extensive reaming and down-hole-cleaning prior to connections, and these are identified as areas which may benefit from data driven optimisation.
An Integrated Methodology for the Unified Optimization of Injection/Production Rates and Surface Waterflooding Pipeline Network Operation Control
Authors: Zhou Xingyuan , Liang Yongtu , Di Pengwei , Xiang Chengcheng , Xin Shengchao , Zhang Haoran
Published: October 2018

As the most commonly used process for the secondary development of oilfields, waterflooding plays a significant role in maintaining reservoir pressure, enhancing oil recovery and achieving high and stable oil production. The previous waterflooding optimization studies usually worked out the optimal injection/production rates but didn't take into account the energy consumed by the surface waterflooding pipeline network system which transfers water from the waterflooding stations to the waterflooding wells. Taking the maximum waterflooding development profit as the objective function, this paper proposes an integrated methodology for the unified optimization of injection/production rates and the operation control of surface waterflooding pipeline network system. The objective function is defined as the oil production income minus the operation cost of the pipeline network. With a given set of injection rates of waterflooding wells, the reservoir numerical simulation is employed to obtain the oil production rates and a mixed integer nonlinear programming (MINLP) model is established for the optimal operation control of the surface waterflooding pipeline network, including the pump schedule of waterflooding stations, flowrate of pipe segments and pressure at each node. A hybrid solving strategy incorporating particle swarm optimization (PSO), linear approximation method, and branch-and-bound algorithm, is proposed for solving the results. The PSO algorithm is adopted to search for the optimal injection rates of waterflooding wells, while the linear approximation method and branch-and-bound algorithm are used for the MINLP model solving. In this study, we took the Daqing waterflooding Oilfield in China as an example. The applicability of the methodology and the stability of the solving strategy are illustrated in detail. It is proved that the proposed methodology could provide the engineers with significant guidelines for the unified optimization of waterflooding process incorporating the reservoir and surface pipeline network.
Application of Low-Carbon, Rodless Artificial Lift in Low-Production, Low-Permeability Oilfields
Authors: Zhu Shijia , Lei Derong , Liu He , Hao Zhongxian , Zhang Lixin
Published: October 2018

The development of a new low-carbon operation mode of artificial lift in high-water-cut oilfields, is significant for reducing energy consumption, improving operation efficiency and lowering production costs of oilfields. The annual electric consumption of the oilfield is increasing year by year. In 2016, the total electric consumption exceeded 35 billion kWh, of which the mechanical production system accounts for 57%.

The rodless artificial lift eliminates the use of the sucker rod, and reduces the installed motor power over 50%. The electric consumption is greatly decreased, while tremendous gain is seen in the system efficiency. Moreover, the application performance is especially good for low-production wells. Under such circumstances, the operation cost of the oilfield declines. The current rodless artificial lift is basically based on two types of pumps, namely submersible plunger pump and submersible direct-drive screw pump.

The submersible plunger pump lifts liquid via vertical reciprocation of the moving body driven by the motor, with daily electric consumption of an individual well decreasing by 46%, from 133.4 kWh to 72.5 kWh. The reduced annual electric cost per well is RMB 14,000, and the annual single-well carbon emission falls by 17.5 tons. As for the submersible direct-drive screw pump, the rotation of the pump is directly motivated by the downhole submersible motor, through which the downhole liquid is elevated to the surface. The daily electric consumption of an individual well decreases by 38.4%, from 224kWh to 138kWh, contributing to the annual electric cost reduction per well of RMB 13,600 and annual carbon emission decline per well of 17.1 tons.

The application of the two types of rodless artificial lift has taken initial shape. The submersible plunger pump has been applied to over 200 wells, and the submersible direct-drive screw pump, over 60 wells. The new low-carbon operation mode of artificial lift is critical for the energy saving, efficiency improvement and consequent cost reduction of oilfields, particularly in cases of the industry downturn triggered by low oil prices.
The Effect of Fines Migration During CO2 Injection Using Pore Scale Characterization
Authors: Othman Faisal , Wang Yamin , Hussain Furqan
Published: October 2018

Recent laboratory studies have shown fines migration induced decrease in rock permeability during CO2 injection. Fines migration is a pore scale phenomenon, yet previous laboratory studies did not conduct comprehensive pore scale characterization. This study utilizes integrated pore scale characterization techniques to study the phenomenon.

We present CO2 injection experiments performed on two Berea sandstone samples. The core samples are characterized using nitrogen permeability, X-ray micro-computed tomography (micro-CT), Scanning Electronic Microscopy with Energy Dispersive X-ray Spectroscopy (SEM-EDS) and Itrax X-ray Fluoresence (XRF) scanning. The core samples were flooded with freshwater, then CO2-saturated water, and finally water-saturated supercritical CO2 (scCO2). To calculate permeability, the pressure difference across the core samples was monitored during these fluid injections. The produced water samples were analysed using Inductively Coupled Plasma-Optical Emission Spectrometry (ICPOES). After the flooding experiment, nitrogen permeability, micro-CT, SEM-EDS and Itrax-XRF scanning was repeated to characterize pore scale damage. Micro-CT image based computations were run to estimate permeability decrease along the core sample length after injection.

Results show dissolution of dolomite and other high density minerals. Mineral dissolution dislodges fines particles which migrate during scCO2 injection. Berea 1 and Berea 2 showed respectively 29% and 13% increase in permeability during CO2-saturated water injection. But after water-saturated scCO2 injection, both Berea 1 and Berea 2 showed 60% decrease in permeability. The permeability damage of the sample can be explained by fines migration and subsequent blockage. SEM-EDS images also show some examples of pore blockage.
Pore Scale Analysis the Formation Dissolution with Capillary Trapping Change for CO2 Injected into Carbonate Reservoir
Authors: Zhang Yihuai , Zhou Yingfang , Lebedev Maxim , Iglauer Stefan
Published: October 2018

CO2 storage in deep reservoir is an efficient way to mitigate climate change. The carbonate reservoir is one of the selected storage sites but which is sensitive to the acidic environment, where the CO2 saturated formation water could be as medium acid in the reservoir condition and hence change the microstructures. However, the capillary trapping mechanism is highly corrected with such microstructures. Thus, fully understand such CO2-water-rock interaction and the related capillary trapping change are very important for the storage security issues. In this paper, we microCT imaged the microstructure change of oolitic limestone sample due to CO2 saturated brine injection, and calculated the capillary pressure based on the fractal theory. We found that the calculated capillary pressure decreased after live brine flooding which indicated a CO2 capillary trapping loss and such calculated capillary pressure change was also highly corrected with the morphology of the dissolved matrix area.
Hydraulic Concentric Tubular Pumping System for Unloading Gas Wells
Authors: Clemens Langbauer , Vita Petr , Gerald Jax , Herbert Hofstätter
Published: October 2018

Conventional artificial lift systems are limited in their application by depth, borehole trajectory and chemistry of the produced media. This paper presents a concentric tubular pumping system, combined with an efficient hydraulic pump to overcome the limitations of existing artificial lift systems and to assure a cost-effective production.

This pumping system consists of a specially designed plunger assembly and barrel combination, which is driven by a hydraulic pressure unit from the surface without any mechanical connection. The hydraulic pump itself can be circulated into and out of the borehole or can be run by slickline, resulting in fast and low-cost operations. The pump is designed to be run as a concentric tubular pumping system with several advantages, especially in enhanced oil recovery and unloading of gas well operations. This new pump type is designed and manufactured in cooperation with the industry and tested at the Montanuniversität Leoben, Austria.

The performance tests have demonstrated the saving potential regarding energy efficiency as well as a reduction in CAPEX and OPEX. The unique design of this pump owns a very low number of moving parts, such no mechanical connection to the surface, and such providing minimal exposure to wear and corrosion. Tests have shown that the pump is very adaptable regarding production rate, which requires just a change in surface hydraulic pressure. Based on experience the concentric tubular pumping system is the best selection for unloading of gas wells to enhance the lifetime of the completions. As a result, of the natural phase separation of liquids and gases, the presented pumping system has shown to be the ideal choice for the usage in all types of wells.

This completely new pump type exceeds the performance of existing artificial lift systems for unloading of gas wells, increases the mean time between failures and reduces the lifting costs essentially. These major issues are most important in times of low gas price.
Optimizing Sand Control Treatments Using Gauge Data
Authors: Jain Samyak , Wassouf Philip , Tibbles Raymond
Published: October 2018

While the importance of pre-job design has always been appreciated, detailed post-job evaluation of gravel pack execution data (both surface and downhole) is equally valuable as it provides a means to learn from past treatments, calibrate models, and improve future designs. Traditionally, post-job analysis has been limited to high-level pack evaluation and failure investigation but has a much wider range of applications in the confirmation of success, better understanding of downhole mechanisms and validation of simulation models. Downhole data analysis techniques can be used to isolate sections of the flow path and develop a more detailed understanding of each stage of the treatment from running in the hole (RIH) to pulling out of the hole (POOH).

Detailed post-job evaluation is often skipped due to the significant effort involved in data handling as well as the lack of a defined workflow and an integrated software tool. This paper provides an overview of the evaluation and calibration of surface and downhole data along with the steps, workflow and tools required to process the data in the easiest and most efficient manner, enabling faster, more detailed and more accurate analysis of operations.

Various case studies are used to demonstrate how post-job evaluation using downhole gauges can be used to efficiently analyse the various stages of the operation including wellbore displacements, reverse and circulating step rate tests and gravel packing operations. A variety of important phenomena are identified and quantified, such as friction pressures, packing mechanisms, fluid displacements, screen plugging and roping, which may otherwise be missed. The paper further illustrates how the defined workflow can maximize the likelihood of success by using post-job evaluation results to better identify and minimize risks during pre-job design stages while reducing the need for excessive safety factors within the operational window.

The analysis workflows introduced here will maximize the value of downhole gauge data and serve as a reference to practicing completion engineers in the efficient processing, analysis and interpretation of post-job data. It can be used to revisit and better understand historical sand control treatments, and continuously improve future treatments.
Rigless Zonal Isolation in High-Permeability and Low-Pressure Sandstone Formations Using an Organically Crosslinked Polymer Sealant: Successful Field Application
Authors: Alshammari Baraa , Rane Nitin , Al Harbi Sultan , Mohammad Safaa , Al-Kinderi Abdullah , Santin Yoann , Matar Khaled
Published: October 2018

This paper describes a rigless and cost-effective field implementation of conformance polymer sealant (CPS) and particulate-CPS (P-CPS) systems used successfully in high-permeability and low-pressure reservoirs for zonal isolation intervention.

The CPS system is an organically crosslinked polymer that is thermally activated to effectively seal the targeted interval. The P-CPS system combines the CPS system with particulates that provide leakoff control to help ensure shallow matrix penetration of the sealant.

The traditional method for zonal isolation consists of rig intervention for cement squeeze, which can be time-consuming and expensive. In high-permeability and low-pressure reservoirs, several unsuccessful attempts can extend the intervention by two or more weeks.

CPS and P-CPS systems provide a predictable and controllable right-angle set time that can help to ensure sealing on the first attempt. These systems do not develop compressive strength, simplifying the cleanup stage by quickly and easily jetting it out of the wellbore with coiled tubing (CT), as opposed to cement that must be drilled/milled out.

This paper describes laboratory evaluations, treatment design methodologies, and two case histories from Kuwait, including one well that produced 1,600 BOPD after reperforations.