bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Approach in Determining Residual Oil Saturations to Water Sorw and its Impact on Potential Enhanced Oil Recovery EOR Volume Estimation
Authors: Murugesu Thanapala S , Masoudi Rahim , Johare Dzulfadly B. , Jalan Shlok , Marzuki Izral Izarruddin
Published: October 2017

Residual oil saturation (Sor) is defined as fraction of pore volume occupied by oil at the end of the oil displacement by a specific fluid. It signifies the ultimate recovery under a given displacement process and represents the endpoint of the relative permeability curves in reservoir simulation. The estimation of Sor is critical in understanding the behavior of the reservoirs during various recovery mechanisms and it is a very important measure used to decide the EOR process selection and feasibility for further exploitation of the reservoir.

The residual oil saturation varies depending on lithology, pore size distribution, permeability, wettability and fluid characteristics. There are several ways to estimate the Sor including core analysis methods, well log methods, and other saturation and volumetric assessment methodologies. However, none of the methods is regarded as a single best method for determining the Sor. In addition, there could be circumstances that the remaining oil saturation (ROS) is misinterpreted as Sor. The integration of various data sources is therefore critical in estimating the true residual and remaining saturations.

This paper highlight number of offshore field case studies where significant difference observed in Sorw estimation using various approaches from core and logs analysis. In these examples, SCAL data and logs in hydrocarbon column as well as swept intervals together with the wells/reservoir performances have been considered in estimating the Sor. It was observed that the production forecasting, reserve estimates, EOR mechanism are hugely affected by the Sorw estimation.
Water Control of Horizontal Wells Using Foam-Gel: Lessons Learnt in a Heavy Oil Reservoir with Strong Waterdrive
Authors: Deng Bo , Liu Wei
Published: October 2017

As technology advances in horizontal well drilling, long horizontals completion are now preferred for producers aiming to explore more oil-bearing zones, especially in heavy or tight oil reservoirs. However, for strong waterdrive horizontal wells, abrupt increase of water-oil ratio and abounding unwanted water production severely affect the profitability of the field due to the constant decrease of oil production and premature well shutting.

The targeted reservoir of this work is a typical heavy oil reservoir with strong waterdrive. By December 2014, the average water cut for the two productive layers has increased 40-70%, for some wells especially, the water cut has exceeded 95% causing frequent well shutin. Therefore, to ensure the productivity of the horizontal wells, water shutoff has become a challenging and urgent task.

According to the aquifer identification and water influx diagnosis, 27 horizontal wells distributed in aforementioned two productive layers were first categorized into two groups in order of treatment difficulties, after which foam-assisted gel and gel treatments were designed and conducted.

For the three of the treated wells, the average water cut was significantly reduced from 80.3% to 48.0%. Although the gross liquid production rates were slightly reduced after treatment from 31.7 to 27.7 t/d, the oil production rate was considerably increased by 28.1 t/d. By January 2016, 4 500 t of the incremental oil was produced indicating the success of the water shutoff jobs. However, it should be noticed that the water cut of the N2 foam-assisted gel treated well started to rapidly rise after two months. This is probably caused by inappropriate foam/gel volume ratio. The water control strategies and field results in this heavy reservoir will provide the necessary clues for the design and application of water shutoff treatments for horizontal wells driven by strong water.
Development and Operational Implementation of Scale Management Strategy in a Mature Field
Authors: Tiwari Amitosh , Fartiyal Prashant , Malik Ankit , Sharma NeelMani , Manickavasagam Chandran , Lele Sarang , Sharma Aastha , Sabhapondit Anindya
Published: October 2017

Calcite scaling is a major production challenge in many mature oil fields. One of the most effective manners to control calcite scaling losses is to predict the scaling behavior in the wells using thermodynamic models and then use prediction results to build an operational program to control scaling in the field using a combination of effective acid washes and scale inhibitor (SI) injection. This paper presents a case study from a mature oil field and details the operational facets of scale prediction and control program. It describes both operational challenges as well as cost optimization involved in program implementation in the field.

There are three major aspects which are discussed in this paper. First part deals with selection of right scale inhibition chemical for a field. It details laboratory experiment that was used to select the most appropriate chemical for the field. Also, this section describes the hardware infrastructure that should be in place to ensure effective implementation.

Next section deals with the trial of chemicals, selected from lab analysis, in actual field conditions. Impact of scale inhibitor in controlling scaling within the tubing and flowarm of the wells is discussed. Secondly, benchmarking of new scale inhibitor chemical performance against the existing chemical is also presented in this section. This formed the technical basis for change in existing scale inhibitor and going for full fledged implementation in the field.

Final part of the paper details field-wide implementation of scale inhibitor injection and chemical performance monitoring program. Critical parameters for chemical performance monitoring and field data on chemical dosage optimization using these critical parameters are presented. This section also presents several case studies showcasing impact of scale inhibitor injection on the well performance.

This scale management approach has not only helped in terms of reducing production losses but also assisted in improving safety performance. Field data, highlighting the impact of scale inhibitor in significantly reducing the scaling in the wells, is shared in this paper. Post implementation of this program, asset has been able to reduce its scaling related production losses significantly (~90% reduction in less than 2 years).

Once an oil field enters decline phase of its life cycle, reservoir pressure drops and water cut increases – conditions which favor high scaling behavior in the wells. Thus, scaling related losses presents a serious challenge in controlling production decline in a mature oil field. By adopting the operational practices shared in this paper, many mature oil field can benefit by reducing scaling related losses.
Characterisation of Readily Bioavailable Compounds in Surat Basin Walloon Coals for Biomethane Production Using Exogenous Culture
Authors: Chen Tianyu , Hamilton Stephanie , Rodrigues Sandra , Golding Suzanne D. , Rudolph Victor
Published: October 2017

This experimental study aims to characterize the bioavailability of six Surat Basin Walloon coals to exogenous methanogenic consortia, and the possible compositional and environmental factors that control bioavailability. Finely crushed coal cores samples were inoculated with digested sludge culture sourced from domestic wastewater treatment plants in biomethane potential bottles (BMP bottles) maintained at mesophilic temperature. Degradation of coal compounds was demonstrated via GC-MS characterization of methanol and dichloromethane (DCM) extracts of coals, as well as analysis of volatile fatty acids and alcohols and total dissolved organic carbon (TOC) in water eluents of coals conducted before and after biodegradation. The resulting methane yields ranged from 14 to 33 μmol/g, with an average of 21 μmol/g (0.515 m3/t) achieved within 30 days. Organic solvent-extractable materials accounted for 3.8 to 12% of coal weight. Aliphatic compounds, primarily medium-long-chain n-alkanes, n-alcohols and esters dominated the solvent extracts. Aromatics were detected up to three fused rings, and are rich in dibenzofuran, alkyl benzene, alkyl polyaromatic hydrocarbons, and acetyl diphenyl. The abundance of solvent-extractable matter was found to rely on liptinite content, particularly suberinite. Preservation of these compounds was thought to be facilitated by vitrinite, such as telinite and collotelinite that are rich in micropores, serving as storage for the hydrocarbons. On the other hand, environmental factors, such as microbes-carrying groundwater might compromise coal extractability by converting coal hydrocarbons to biogas. The study has revealed three levels of dependence regarding coal bioavailability: 1) Water solubility - An average 98% of aqueous compounds (based on TOC) was eliminated via biodegradation. These were mainly volatile fatty acids and alcohols, and to a lesser degree, medium-chain n-alcohols, esters and aliphatic amine; 2) Solvent extractability – approximately 35% of solvent-extractable compounds were biodegraded on average, with aliphatics being more bioavailable than aromatics; 3) Heterogeneous moieties, particularly aliphatic hydroxyl, ester bond, ether bond and C-N bond in aliphatic amine - These functional groups are characteristics of compounds that were heavily degraded. The study is to our knowledge, the first coal bioavailability research that demonstrated a detailed linkage between biomethane generation and bio-elimination of coal extractable compounds with connections to petrographic composition and possible environmental factors.
Enhanced Efficiency in Deep Water Testing Operations Delivered by Smart DST String
Authors: Amir Shah Jayachand , Aminuddin Mior , Fatah Al , Fyfe D. , Justin Metrol
Published: October 2017

This paper discusses the smart Drill Stem Test (DST) string, run for a Deep Water (DW) well test operation, which enabled considerable saving of rig time, reduced risks, and provided best reservoir data quality, while performing a commingled DST in a single run. Evaluation of the zones was made without any wireline intervention runs such as Production Logging Tool (PLT) or Surface Read Out (SRO). Acoustic telemetry provided seamless access to downhole data, including production profiles from both zones, throughout the DST operations.

This paper will help the well testing fraternity conduct well test operations efficiently and safely in a deep-water environment using new technology tools and innovative methods. Well testing costs and risks can be reduced significantly.

The smart DST string, run in hole (RIH) for the DW well test, consisted of a combination of conventional DST tools, a new generation packer and below packer, acoustically operated tools including: Acoustically Operated Sliding Side Door (SSD) - provided access to the reservoir for Well Kill Operations after the standalone screens became plugged with unconsolidated sand and Loss Control Material (LCM) pills.Multiple Discrete Temperature Sensor Array - Eliminated the requirement of running a conventional PLT to evaluate the commingled flow of two zones, provided valuable production logs, and resulted in unexpected, additional information evident from the thermal transient data.Acoustically Activated Bottom Hole Samplers - collected bottom hole samples selectively, at different drawdowns, without wire line intervention or without applying annulus pressure.Wireless Gamma (GR) Depth Correlation Tool - Provided accurate TCP gun placement, without running a conventional wireline GR/CCL, by using a tubing conveyed Gamma Ray logging tool; results were collected wirelessly in less time than a conventional wireline run.New Generation Packer -The large size 9-5/8" Hydraulic Set Retrievable seal bore type packer was used for the first time by the company. This is a most suitable packer for DW DSTs, which eliminated the requirement for slip joints, drill collars and safety joints or the running of a permanent packer, which would have required multiple trips and restricted the gun size.
Application of Well Factory Drilling Technology in Shale Gas Development in the Sichuan Basin
Authors: Yang Liu , Ping Chen , Shou Ma Tian
Published: October 2017

The shale gas field in Sichuan Basin is located in a complex mountains and hilly areas, and the predrilling and drilling operation are difficult and costly due to well site logistical limitations. Therefore, based on many successful case histories of factory drilling and completion work in the North Amercia, and considering the terrain and the geologic and development characteristics of shale gas reservoirs in the Sichuan Basin, an applicable "factory drilling" model was established. In this case, "factory drilling" involved standardizing predrilling engineering, optimizing design of exploration and drilling operations, streamlining engineering, launching an assembly-line drilling operation, establishing a comprehensive utilization of resources and uniform and integrated crew management as its foundation. The standardization of predrilling engineering contained well patterns arrangement and well site deployment, well patterns adopted cluster well with single or double row, 8 wells at the most in a single well pad and the maximum distance between wells is 600m. The drilling engineering optimization design included well trajectory design and interwell anti-collision calculation, the extending direction of the horizontal section was orientation of the maximal horizontal principal stress. The engineering module included the PDC bit selection, drilling methods and matched technical modules. Assembly-line drilling operation involves batch drilling in the same section and reclaiming the waste drilling fluid according to the situation. The field test results indicated that factory drilling could help increase rig operation efficiency, shorten well construction cycle, improve the comprehensive utilization rate of resources, and reduce the waste fluid discharge in the working areas. In WeiYuan shale gas district, there was a sharp decrease in the average well construction period, from original 149d (well W201H3) to the present 72d (well W204H1-3), the corresponding ROP improved from 2.67m/h to 8.35 m/h, and recycling rate of drilling fluid are reached 70%. This study provided a new idea and a reliable technological means to achieve the high-efficiency and low-cost exploitation of unconventional natural gas resources.
Unlocking Reservoir Potential through Rigorous Surveillance and Field Review Post FDP: Case Study on Central Luconia Carbonate Gas Field
Authors: Sow Chia Shen , Bashir Aamir , Chowdhury Utpal , Hajizadeh Alireza , Ridzuan Ahmad Idriszuldin
Published: October 2017

For E&P upstream player, the most exciting oil and gas development project is to transform a commercial hydrocarbon resources into readiness for production to meet the company investment portfolio. It involves field development planning, design, technology, procurement, construction, drilling and start-up prior to handover to production operations.

Most of the times, economic evaluation, assessment of risk and return on investiment (ROI) from the project are the key factors to determine the fate of the project during feasibility study and/or before the Final Investment Decision (FID) phase. Moreover the project cost, schedule, reserves to be developed and production profile are the key parameters to dictate the cash flow and net present value.

The general practice is that once the project completed, the reservoir model will be updated with new findings and surprises observed during drilling phase and include in post drilling evaluation report. After this stage, the project team will be disbanded and most companies will be lacking a single point of accountability for delivering production as promised1. Once all the requirements and expectation have been met, the project is considered to be successfully delivered.

In this case study, the real time production and survelliance data were analysed. Although initial production did not meet the FDP delivery target due to project delays and subsea facilities downtime which causes production deferment, the stabilized production trends with time indicated a potential reserves gain by about 50%.

In summary, the analysis shows the value of analyzing the production and surveillance data by a dedicated team to assess the current field performance compared with the forecast profile from FDP study. The deviation can be a triggering point for revision on the resources figures, future infill opportunities and may contribute to the future cluster development within the same PSC.
Production Optimization of Raageshwari Field Using Network Modelling
Authors: Bhardwaj Charu , Godiyal Preeti , Mathur Mohit , Ranjan Amit , Verma Saurabh K.
Published: October 2017

The Raageshwari field is situated within the RJ-ON-90/1 Contract Area. Of the seven producers which have been completed, six flow naturally and one is on artificial lift.

A network model was created to verify the maximum producing potential of the field as well as identify any bottlenecks in the system. The model could then be used to evaluate de-bottlenecking options before going into full field implementation.

The production potential of each well was categorized into three parameters: Reservoir Maximum Production Potential (RMPP) i.e. the maximum theoretical production that the reservoir can deliver at the sand-face, Well Maximum Production Potential (WMPP) i.e. the maximum production that well can deliver from sand-face to choke valve, and Plant Maximum Production Potential (PMPP) i.e. the maximum production that the surface facilities downstream of choke valve can handle. These values were generated using the Network Model and the lowest of these was termed as Lowest Maximum Production Potential (LMPP). Sensitivities were carried out in the model to identify constraints limiting the production potential of the field. The model was then used to predict the effect on production of removing these constraining factors. These predictions were then evaluated based on the cost to implement and their economic value. The study indicated that the field production can be increased by 20% with payback time of 7 to 10 days. This workflow for production optimization can be applied to similar marginal fields.
Flexible Cement Extends Wellbore Life with an Integrated Approach to Zonal Isolation
Authors: Kumar Animesh , Gupta Gaurav , Mehra Rohit , Tambe Romana , Ahuja Gopal
Published: October 2017

Sustained casing pressure (SCP) is a major risk encountered in most wells in India, particularly in developmental oil and gas fields situated in the northwest area of the country. The inability of conventional cement systems to withstand cumulative stresses from completion and production phases might be one of the primary reasons for the failure of expected barriers during zonal isolation, which can lead to SCP. This case study reviews a flexible cement system used in an oil and gas field located in northwestern India, including extensive laboratory evaluation, operational design, execution, and well evaluation.

The field requirement was to design a gas-tight, lightweight slurry for a production zone to treat losses and address issues of SCP. A finite element analysis (FEA) structural simulation was performed, which modeled the lifetime operation of the well. Including elastomeric and tensile strength enhancement materials in the cement system was recommended based on results from structural simulation to reduce risks of SCP. Incorporating these materials can enhance a cement system's mechanical properties (i.e., increase Poisson's ratio and tensile strength and decrease Young's modulus). The slurry was designed with cement, hollow spheres, lost circulation material (LCM), a tensile strength enhancer, and elastomeric material; the cement slurry was batch mixed to ensure homogeneity.

The case study examines the impact of the fluid rheological hierarchy, pump rates, and multiple bottom plugs on cement slurry displacement efficiency using computational fluid dynamics (CFD). A finite-difference, three-dimensional (3D) displacement simulator was used to predict the flow behavior of fluids, both inside and outside the casing, throughout the operation using actual operational parameters. Based on two-dimensional (2D) hydraulics analysis, various factors, including rheology, pumping rates, and fluid density, were adjusted to maintain equivalent circulating densities (ECDs) below the fracture pressure to help avoid losses.

A tailored cement design, which created a stable gas-tight resilient cement system, helped minimize risks to production by achieving effective zonal isolation. This was confirmed through a post-operation review. The cement bond log, including a microseismogram and circumferential visualization, indicated that the cement was adequately placed around the casing.

The increase in the cement system tensile strength helped ensure wellbore integrity, even in high-stress/strain load cycle production environments. Cementing operation success was confirmed by excellent cement bond logs and zero SCP observed between the production and surface well casing annulus.

The life-of-the-well tool is an engineered, proactive, and interventionless zonal isolation solution to help extend well economic life, thus preserving production while reducing or even eliminating costly remediation (Ravi et al. 2002).
Success and Lessons Learned from ASP Flooding Field Tests in China
Authors: Guo Hu , Ma Ruicheng , Kong Debin
Published: October 2017

ASP flooding is proven a great success in China due to its large number of field tests and incredible oil production. Latest progress of ASP flooding field tests and application in China is summarized. Incremental oil recovery of ASP flooding can be as high as 30%, much higher than all the other chemical enhanced oil recovery (CEOR) techniques. Although one recent surfactant-polymer flooding (SP) field test is reported 18% incremental oil recovery, other SP flooding field tests are not so successful. More incremental oil recovery does not always ensure more economic benefits. With progress of surfactant production technology in Daqing, alkali NaOH was finally proven better than Na2CO3. Too high polymer concentration may block low permeability strata. The allowable maximum polymer parameter (molecular weight and concentration) is key to success, especially when emulsification is taken into consideration. There is no one-fit-all ASP formulation and the dynamic adjustment is necessary in ASP flooding. Why pre-slug is used is still worth investigation. The average cost of ASP flooding can be lower than SP flooding due to more oil produced.
Online Monitoring and Automatic Control for Zonal Polymer Injection Wells
Authors: Fuchao Sun , Xiaohan Pei , Deli Jia , Guanglei Gao , Guoqin Li , Xiaoyan Wang , Chongjiang Liu
Published: October 2017

Polymer flooding has been improved an effective way for EOR in China. Comparing with waterflooding, zonal pressure and flowrate change much larger for polymerflooding duo to its high viscosity. Reservoir engineer are required to adjust flow allocation scheme frequently when pressure change. However, traditional zonal polymer injection technique can not obtain zonal parameters during injection process. The flowrate adjustment has been done by fishing downhole choke by steel wire. Usually, the fishing operation was implemented many times. The efficiency is poor. This paper introduced an online monitoring and automatic control technology. A instrument was used to realize zonal polymer measurement and adjustment. There is no need for downhole fishing tool. Considering viscosity decrease control, a downhole streamline slot adjustable choke was development. The lab test indicated the viscosity decrease rate can be controlled within 10% when flowrate vary from 10-60m3/d. At the same time, the flowrate can be adjusted according to set point by instrument. And it can also be regulated at any time manually just needing pushing the mouse in the office. This technology has been applied more than 200 wells in Daqing. The downhole instrument is mainly consisted of mechanical arms, control part, measuring part and guiding mechanism. Comparing with waterflooding, the torque output for polymer injection well is much larger. Torque output of water flooding is only 3-5N.m, however, it can increase by more than two times to 8-12N.m for polymer flooding. Meanwhile, on-line torque monitoring function is added to effectively prevent excessive current that damages the motor and adjustment success rate. Considering the flowmeter based on internal magnetic may result in polymer blocking, external magnetic type flowmeter was used to avoid affects due to polymer plugging. The technology has been applied in 60 polymer injection wells by the end of 2016 and the test time of average single well is shortened from 5.2 days to 2.5 days which means the efficiency is more than two times higher. At last, a case study was introduced.
Modelling and Analysis on High-Fidelity Fine-Scale Reservoir Simulation in Mature Waterflooding Reservoir
Authors: Shuhong Wu , Jiangyan Dong , hua Li , Qiaoyun Li , Baohua Wang , Tianyi Fan
Published: October 2017

Today the oil development in the world goes into a new area, in which the complex and special oil reservoir are becoming the main development objects gradually to meet the ever-growing need for energy. Especially in china, most of the oil reservoirs are located in continental basins characterized by serious heterogeneity. And many mature reservoir entered into high water-cut stage after several decades' development. Thus, with the increase of the complexity of the reservoir and its development, reservoir simulation becomes increasingly very complicated. A high-fidelity and fine-scale reservoir simulation with high performance is needed to analyze the complex flow process, simulate the production history and forecast the future performance.

In this paper, the high-fidelity and fine-scale reservoir simulation focus on three aspects, which are flow modeling, fine grid and high-performance mathematic method. The flow and formation model is designed to actually describe the complex flow process of oil, water and gas as well as time-dependent variation of reservoir properties such as permeability and porosity in mature water-flooding reservoir, such as fault, pinch and heterogeneity, which is helpful to simulate water-flooding front and water channeling. The computational mathematical method with high-level pre-conditioners is designed to ensure solving the large simulation mathematic problem with high speed and high performance.

The results shows that the fine-scale simulation is helpful to identify the water displacement front, especially, water channeling which might occur and result in sudden water cut increase during the water-flooding. Also, the high-fidelity and fine-scale modeling more accurately describe the remaining oil and better match the production performance such as the oil and water production trend. As an auxiliary tool, it helps to identify the location of new well in the rejuvenation of mature field. Thanks to the high-fidelity and fine-scale simulation, two new wells are designed and drilled in the area of high remaining oil of ZY reservoir, which both get encouragingly high daily oil production and low water-cut.
Highly Efficient Nano Boron Crosslinker for Low-Polymer Loading Fracturing Fluid System
Authors: Wang Kun , Wang Yanling , Ren Jinheng , Dai Caili
Published: October 2017

Guar gum and its derivatives based-gels crosslinked with boron have been utilized in hydraulic fracturing for decades. However, these gels have a noticeable limit-large polymer loading which causes problems including large quantity of residues and low regained permeability. Besides, to achieve optimal thermal stability, conventional boron crosslinker must be utilized at high pH. To overcome the above limitation of conventional boron crosslinker, we proposed highly efficient nano boron crosslinker for low polymer loading fracturing fluids.

Boron-modified nanoparticles were synthesized by two-step surface modification as nano boron crosslinker (NBC). First, (3-Aminopropyl) triethoxysilane was coated onto the silica nanoparticles surface obtaining amino-modified nanoparticles JT-1. Second, Organic boron (OBC) was coated onto JT-1 resulting in boron-modified nanoparticles (NBC). Characterization was given using FTIR spectroscopy to prove the presence of surface modifier and transmission electron microscopy (TEM) to study the particle size. The effect of pH and mass ratio of JT-1 and OBC on rheological properties of hydroxypropyl guar (HPG) gels crosslinked with NBC was investigated. The microstructures of NBC crosslinked-gels was visualized via Scanning Electron Microscope (SEM).

The results of FTIR spectroscopy illustrate the presence of amino on the surface of JT-1 and OBC was bounded onto the surface of JT-1 by B-N. The particle size of NBC ranges from 20 to 40 nm. NBC crosslinked0.3 wt.% gels exhibit a unique rheological performance at 100°C. The viscosity of OBC crosslinked-gels shows a tendency of first increase and then fall as pH ranges from 7 to 14 and peak viscosity was achieved at pH 10. Whereas, viscosity of NBC crosslinked-0.3 wt.% gels increased continuously from 44.72 mPa•s to 327.8 mPa•s as pH rises from 7 to 14. The remaining viscosity (viscosity after shearing at 170s−1 for 60 min) at 100 °Cof NBC-crosslinked 0.3 wt.% HPG gels remains higher than 50 mPa•s at pH 8 -14, indicating that NBC crosslinked-gels possessed great thermal stability at low polymer loading over a wide pH range. The difference between microstructures of NBC crosslinked-gels at different pH may be responsible for the effect of pH on the thermal stability of NBC crosslinked-gels. Gels crosslinked at higher pH gave a more coiled 3D microstructures with considerably higher structure density compared with those crosslinked at pH 7.

The hydraulic fracturing fluid system crosslinked with surface modified nano boron crosslinker showed great thermal stability at low polymer loading (0.3 wt.%) over wide pH range (8-14). Due to its unique crosslinking properties with HPG, nano boron crosslinker may provide an excellent solution to the limits of conventional boron crosslinked gels.
Statistical Analysis and Mapping of Oil and Gas Operating Cost Based on Field Development Plan in Indonesia
Authors: Azizurrofi A. Abdul , Asnidar A. A. , Galih D. R. , Hermawan A. H. , Buana Y. S. , Firdaus R. R.
Published: October 2017

In early 2016, oil price has fallen to its lowest level (31.68 US$/bbl) over the last 12 years. Since then, petroleum exploration and exploitation activities are decreasing worldwide due to high production cost and low oil prices.

As of November 2016, there were 403 field development plans (FDPs) approved by the government of Indonesia in 2003 – 2016 period. In 2015, there were 57 approved FDPs, which became the largest number of FDPs approved since 2003. The increasing number of approved FDPs indicates that the fall of oil price had no big impact on the number of projects (FDPs) in Indonesia. The oil and gas industry in Indonesia is still considered attractive by contractors.

Before investing in the oil and gas industry in Indonesia, there are some of ways that can be done by investors to minimize risk of loss and maximize revenue such as, searching, finding and collecting data of cost expenditure (Capital and Operating Expenditure) and commercial reserves across Indonesia, analyzing social issue that may occur in oil and gas exploitation area, considering infrastructure and geographical area (remote area or not), etc. This paper will collect and evaluate the operating cost of production of 403 approved FDPs and analyze the correlation between the operating cost of 403 FDPs and the world oil price, and create maps showing the distribution of operating cost in each clustered area in Indonesia.

For the purpose of this paper, the geographical areas of Indonesia were divided into 6 different areas (Sumatera, Natuna Sea, Java, Kalimantan, Sulawesi and Papua). Then, the data that related with Operating cost of oil and gas production from 403 FDPs was collected and then the operating cost was calculated and distributed to those aforementioned areas. Finally, areas that had the lowest and the highest operating costs of oil and gas production were defined.

Based on analysis of 403 FDPs, the western area of Indonesia had the highest Operating cost of oil and gas production. The highest Operating cost was equal to 7.91 US$/bbl and located in Sumatera, meanwhile the lowest Operating cost was equal to 3.22 US$/boe and located in Kalimantan.

Hopefully, this paper will provide contractors (Investors) with a quick look at oil and gas industry in Indonesia especially related to cost of oil and gas productions and help them to build their oil and gas portfolios before making decision to invest in the oil and gas industry in Indonesia.
Capillary Pressure Drainage Curves: Modelling and Prediction of Capillary Entry Pressure
Authors: Behrenbruch Peter , Kennaird Tony , Duy Bui Khang , Do Huu Minh Triet
Published: October 2017

Capillary pressure (CP) measurements on core samples generally deploy one of three tests: porous plate (PP), centrifuge (CF) and mercury injection (MI). The first two mentioned tests are most often used to directly determine a CP relationship and the PP procedure most closely conforms to reservoir situations. CF test results may be superior for certain types of plugs and testing conditions, not to mention that testing is considerably faster. MICP tests are typically used for determining pore size distributions but may also be used to generate CP curves, with best results obtained by validation against the other two tests. MI tests also have the shortest timeline.

CP curves have been modelled (fitted or matched) over the years with many alternative formulations, from the well-known J-function approach (Leverett, 1941) to more recent methods. Some formulations can realistically match the low pressures of CP profiles, including capillary entry pressure, while others do not cater for it at all. When the low-pressure part of CP curves exhibit a "roll-over effect (concave downward profile), entry pressure prediction may require high frequency data from MICP testing to give more definition.

This paper examines several CP data sets, comparing PP and MI results, in light of pore throat distributions. Seven formulation are used to match entire CP profiles from PP data and are subsequentlyexaminedfor being able to represent capillary entry pressure. Various types of pore structures are discussed: homogeneous (narrow distribution), broad (poorer sorting) and bimodal (two distinct distributions) where the smaller pores are often related to pore-fill. It is shown that the Modified Carman-Kozeny Purcell (MCKP) formulation (Behrenbruch et al, 2011) is excellent in capturing the level of entry pressure for narrow pore throat size distributions or homogeneous plugs while entry pressure prediction for poorer sorted plugs tends to be less accurate, partially due to variation in samples.The detailed modelling of the roll-over effect requires a separate model. A new and improved correlation for (model) capillary entry pressure has been derived, showing results from Australian and other fields.
Optimal Zonation of Geological Formations and Identification of Pore Structures for Sandstone Reservoirs, Including Variation in Cementation and Fining Sequences
Authors: Behrenbruch Peter , Hoang Tuan G. , Huu Minh Triet , Bui Khang D.
Published: October 2017

Hydraulic Flow Zone Unit (HFZU) analysis for characterising cored formations using the Carman-Kozeny (C-K) equation was first proposed in the late 1980s. More recently this formulation was amended as for diverse formations, the C-K equation typically works in less than 50 percent of the cases. The modified formulation includes a cementation factor to handle C-K non-compliant cases. The objective of this paper is to build on these formulations, covering the full range of geological situations.

The study presented compares traditional reservoir characterisation approaches with the latest geological zonation techniques, showing how the full range of relationships may be universally accommodated. Such zonation is the best preparation for optimal reservoir simulation. In particular, it is shown how variable grain size and sorting may be visualised. Results are presented in traditional space, logarithmic permeability vs. porosity, and in model space: hydraulic radius, or reservoir quality index vs. porosity group, porosity fraction divided by the solid fraction.

It is shown that the methodology presented can deal with any sandstone (clastics) situation: C-Kcompliant and non-compliant, further categorising variable cementation and other diagenetic features, and including interbedded intervals and fining sequences. The zonation of a geological interval using the methods presented is the best basis for choosing vertical gridding for a dynamic reservoir simulation model, circumventing traditional upscaling, often fraught with inconsistencies. It has been found that the Flow Zone Indicator, a measure of grain size (or pore throat size) is the best parameter for zonation, followed by sorting of grains or pore throats. A Global Characteristics Envelope, encompassing 6 dimensions, is used to further validate final results.

The paper presents several case histories, covering fluvial and marine environments and a range of geological depositions and facie, including pore-fill (typically kaolinite). Fields are located offshore Australia and overseas.
Evaluation of the Kinetics of Asphaltene Flocculation during Natural Depletion and CO2 Injection in Heptane-Toluene Mixtures
Authors: Kord Shahin , Dashti Hossein , Zanganeh Peyman , Ayatollahi Shahab
Published: October 2017

Carbon dioxide miscible flooding is known as a very efficient and challenging enhanced oil recovery (EOR) method. Besides the high oil recovery efficiency, the asphaltene precipitation and deposition is believed to be triggered by a perturbation of the thermodynamic equilibrium present in the reservoir. Asphaltene deposition results in wettability alteration and plugging in the reservoir as well as affecting the production facilities. The complicated mechanism of phase separation in asphaltene-containing systems makes it crucial to study the effects of different parameters on the aggregation of asphaltene particles.

In this study, a novel high-pressure visual cell equipped with a high-resolution microscope along with the image processing software was prepared to investigate the growth of asphaltene particles on a sample reservoir rock. The quantity of asphaltene deposition was determined at several pressure depletion steps and different temperatures with and without CO2 injection. This would help to evaluate the kinetics of asphaltene flocculation resulting from CO2 injection or pressure drop due to natural depletion. The results reveal that the amount of asphaltene deposition increases with increasing the concentration of the injected CO2. The results of this study demonstrated that the molecular structure of asphaltene could have a noticeable effect on the asphaltene deposition.
Optimization Method for Casing Design Based on Coordination Mechanism of Drilling Risk and Cost
Authors: Sheng Ya-Nan , Guan Zhi-Chuan , Wei Kai , Zhao Ting-Feng
Published: October 2017

Because of the complex geological structure and unpredictable geologic environment, drilling engineering is characterized by high risk and high cost, especially the drilling processes of complex formation or deep water condition. Controlling drilling cost and ensuring the drilling safe has been the focus of research at home and abroad. So this article's objective is to establish the casing program optimization method based on risk and cost coordination. In this article, based on the drilling quantitative risk assessment and the drilling accidents report, the risk probability profile can be obtained. Then according to the theory of fuzzy mathematics, the model of risk degree judgment was established. The drilling risk probability profile is divided into three parts: the safe region, the transitional region and the dangerous region. No special treatment is necessary for the safe region. Risk in the dangerous region must be avoided before drilling. The risk in the transitional region must take account of both risks and costs. The risk treatment and aversion cost calculation model were established. Then the coordination of drilling risk and cost was proposed. Finally, the optimized casing program based on this method was obtained. After the summarization of this principle, taking the drilling data of one block of a basin in west China as the example, the risk level identification results were mainly identical with the realities, and indicated that the method could satisfy the needs of drilling engineering. Case study showed that the decision making for casing design of one pre-drill well was optimized based on the coordination mechanism. The well was successfully completed without risks and the drilling cost decreased by 15%.
Enhanced Reservoir Characterisation Using Integrated Production Data Analysis
Authors: Motaei E. , Ataei A. , Yazdi E. , Khor Y. Y. , Faiz M.
Published: October 2017

Production data analysis (PA) refers to all analytical approaches and tools to reveal reservoir properties, performance, and characteristics such as material balance, Flowing Material Balance (FMB), Pressure Transient Analysis (PTA), Rate Transient Analysis (RTA), Decline Curve Analysis (DCA) and deconvolution.

PA provides robust information comprising reservoir container volume, depletion mechanism, reservoir connectivity and well performance. It provides the best view on reservoir performance and helps to characterize the reservoir to understand reservoir quality, boundaries and flow characteristics to develop and optimize current reservoir management prior to any dynamic modelling.

In this paper, the focus will be on analytical methods such as Rate Transient Analysis (RTA), Flowing Material Balance (FMB), Pressure Transient Analysis (PTA) and analytical simulation as an integrated approach for enhanced production data analysis in Gas fields. The idea of FMB has been introduced by L. Mattar (1997) and it is generally applied to determine oil or gas in-place using flowing pressure data (L. Mattar and Anderson, 2005).

The main objective is to show the methodology for production data analysis, illustrate its added value to reservoir performance monitoring as well as its advantages for well-test design and production forecasting.

The results show that different approaches need to be used consistently to enhance the reservoir characterization and improve reservoir understanding in using production data prior to full field dynamic application. Integration helps to resolve uncertainties quickly and economically.
Drilling Optimisation of Extended Reach Multilateral Wells to Maximise Reservoir Contact in Carbonate
Authors: Verma Chandresh , Rodriguez Fernando , Qasin Qazi Mohammed , Chaaouri Aramco Mohsen , Akel Sami , Akiki Ghassan , Afolabi Jonathan
Published: October 2017

Energy consumption and demand are steadily increasing. Hydrocarbons have been an important energy provider for several decades, but production from mature oil and gas producers is declining. Great effort is put into improving oil and gas reservoir recovery to meet this rise in energy demand.

In the subject reservoir where the pay zone is a thick, multi-layered limestone, characterized by low-permeability; conventional techniques yield lower than expected production results.

To improve production and the ultimate recovery of the field, extended-reach drilling (ERD) wells with long horizontal multilaterals (Quad and Penta-laterals well types) were drilled to attain maximum reservoir contact (MRC), ranging from 10 to 14 Km. These wells equipped with intelligent completions, enable uniform contribution along the extended horizontal intervals. This contribution is achieved through better flow management of the different sections of reservoir contact, reducing operational drawdown pressures, and delaying gas and water breakthrough. The result is high well potentials, improved long-term performance of sweep and recovery, and increasing net worth of the drilling investment.

This paper presents the lessons learned from hundreds of ERD multilateral wells drilled in the field, including integrated operations, progressive approaches and innovative applications, improved drilling practices on a continuous basis, and the tools and techniques used to drill and complete the wells safely and efficiently.

These efforts achieved a milestone record rate of penetration (ROP) in the Middle East of 5,000 feet per day, and as a direct result contributed to minimizing well delivery time by 35 % and average 25% reduction in well cost in an always challenging drilling environment.

The design approach, job execution and evaluation of drilling performance are presented in this paper; as well as key technical challenges and risks encountered during planning and execution stages and how these were mitigated and overcome for MRC improvement and optimization.

Well construction was challenged to meet the complex multi-lateral with long cantilever sections.

The MRC optimization schemes applied in the field resulted in dramatically reduced days of drilling operations that led to millions of dollars in project savings and the achievement of world class drilling records.