bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Model Parameterisation and Objective Choices on Assisted History Matching and Reservoir Forecasting
Authors: Hutahaean J. J. , Demyanow V. , Christie M. A. 
Published: October 2015

Abstract
Assisted history matching (AHM) can be approached either by single objective (SO) or multi-objective (MO) optimisation. AHM generates multiple matched-models, which are then used to quantify uncertainty of the forecast. The goals in this framework are not only to produce matched-models in an efficient way but also to provide a reliable forecast under uncertainty. Choice of the model paramaterisation is one of the sources of uncertainty in reservoir modelling. This is usually done based on geological information and engineering knowledge.
This paper explores the impact of different geological model parameterisations on AHM and its impact on the reservoir forecasting. It compares the performance of SO and MO AHM approaches under different model parameterisation. In the MO approach, different choices of objective grouping were studied. Three performance measures in AHM and forecasting will be discussed, namely: diversity, convergence, and forecast reliability. Diversity is defined as set of models that are different but still match history. Convergence is defined as how fast history matching achieves the desirable match. Reliability, for synthetic case study in the present paper, is defined as encapsulation of a simulated truth case into the probabilistic range of forecasting (P10 – P50 – P90).
Study on a standard industry benchmark case in this paper shows that MO optimisation approach provides a more diverse set of matched-models, which leads to a better forecast. It also confirms that a MO approach is more robust and reliable in forecasting than SO under different model parameterisation. Different objective grouping choices in MO approach still give a reliable reservoir forecasting, although variability in convergence rate is seen.
Mature Field Revitalization: Analysis of Wellhead Compression to Enhance Productivity from a Mature Retrograde Reservoir
Authors: Jain S. , Al Hamadi M. A. , Jaber S. , Jany A. B. 
Published: October 2015

Abstract
Sajaa gas field is one of the oldest fields in the Northern Emirates operated by Sharjah National Oil Corporation (SNOC) where Petrofac currently holds accountability for the Sajaa asset operations until November 2015. Since 1982, this mature asset has experienced increasing gas recoveries with declining reservoir pressures subsequently leading to condensate banking and liquid loading problems. Many techniques had therefore been adopted including drilling of multilaterals, plant inlet compression and foamer, but the effects were short lived as the reservoir pressure declined further. This paper deals with the latest production enhancement technique involving field wellhead compressors applied on the asset to increase its deliverability and longevity.
This project involves the installation of 12 Well head compressors which effectively aim to include the entire inlet from the field through these units. A total of 18,600 HP of compression has been introduced throughout the field with these fuel gas powered reciprocating compressors, including a primary separation unit on each skid. They have principally been able to reduce the flowing WHP to as low as 15 Psig associated with a reduction of DeltaP across the wellbore, thereby reducing the effect of liquid loading and aiding to an increase in the primary condensate and water recovery. The scope of this paper is the analysis of the Full field compression (FFC) project providing an overview of the installation methodology, performance of the wells and the incremental effect of the project which exceeded the forecasted gain, along with troubleshooting from a subsurface point of view. Finally using the Integrated Asset Model to link the subsurface performance to the surface gain and forecasting the increment of reserves associated with the FFC in a mature retrograde carbonate reservoir environment. An insight into the factors influencing the compressor performance and the optimization techniques employed during the 2 year long project is also presented.
Swing-Rod Flowmeter - A New Downhole Flow Measurement Technology
Authors: Lichen Zheng , Jiaqing Yu , Xiaohan Pei , He Liu , Zhengyun Zuo 
Published: October 2015

Abstract
In the process of separate layer injection and production, downhole flow measurement is always a difficult problem and is the bottleneck for realizing flow automatic control. To solve this problem, a new swing-rod flowmeter is disclosed in this paper.
The structure of the swing-nod flowmeter mainly comprises a sampler, a swing-rod, a displacement transfer rod, a target and a sensor etc. A hollow swing-nod which inserted in the measuring tube is used as the sensitive element. At the end of swing-nod is a sampler which is used as the sampling element of the fluid to be measured, Eddy current displacement sensor is used as sensitive element to measure the displacement of the target. The working principle is: when fluid flowing thought the sampler, a displacement of the swing-nod is produced. The displacement reflects the rate of flow. The displacement of the swing rod is transfer to the electronic cabin by the transfer rod, by measuring the displacement of the target mounted on the transfer rod, the quality of the flowing fluid can be measured accurately.
Downhole flowmeter is required to be with high working pressure, long service life, strong anti-interference ability and small volume. Especially for the battery-powered metering system, low power consumption is necessary for flowmeter. The Swing-rod flowmeter presents excellent performance, the working pressure can reach 70Mpa, range ratio is 30, the minimum flow measurement is 0.5m3/day, and measurement precision is 3%. The advantages of the swing-rod flowmeter include: high working pressure, low power consumption, compact structure, wide measurement range, convenient range adjustment and strong anti-interference ability. The Swing-rod flowmeter is suit for downhole flow measurement.
In one hand, the pressure is very high in the downhole environment, in the other hand, small flow measurement require high sensitivity. The existing flow measurement technology is hard to be used in downhole flow measurement directly. Swing-rod flowmeter provides a perfect solution for downhole flow measurement and flow control; it has been successfully used in separate layer water flooding system.
Successful Drilling of First CBM Horizontal Wells in Indonesia Through Meticulous Drilling Design and Geomechanical Analysis
Authors: Syed Anzar , Patterson Jason , Supriyanto Erick , Hsu Ding , Setiawan Ade Surya , Bahuguna Somesh 
Published: October 2015

Abstract
Drilling horizontal wells in soft formations can pose significant risks that require careful planning and execution. During 2014, Virginia Indonesia Co. Limited (Vico) successfully completed two surface-to-inseam horizontal wells to appraise coalbed methane (CBM) production potential on their Sanga Sanga license in East Kalimantan, Indonesia. Both wells passed through soft shales and coals that exhibited breakouts in offset wells, in addition to heavily depleted zones exhibiting large fluid losses in an area well known for shallow gas blowouts. Geomechanical analysis of information from nearby offset wells was used to determine the mud-weight window and fluid properties required to effectively manage these conditions. The results were incorporated into the preliminary well design and planning, and with model matching carried out in real time while drilling operations were underway, any deviations in wellbore integrity were managed as they arose.
The drilling success was, in large part, a result of extensive preplanning and a regimented approach to how the wells would be drilled and any instability dealt with promptly. In addition, real-time monitoring that identified deviations from model-based predictions provided invaluable information for planning subsequent wells. The methodical approach to planning and execution of these wells led to their successful completion, with the results potentially reshaping the Indonesian CBM and energy industry.
Research of Enhancing Heavy Oil Recovery By Steam-Air Combination Flooding
Authors: Yang Jian , Li Xiangfang , Xu Darong , Yan Yiqun , Li Jing , Fang Sidong , Zhang Baorui 
Published: October 2015

Abstract
In order to enhance the recovery of heavy oil, the paper mainly studies the in-door experiment and numerical simulation of the steam-air combination flooding. The experiment contains 7 sub-experiments: steam flooding, steam-air combination flooding including mass ratio of air and steam from 1:32 to 6:32. After the research of different mass ratio of air and steam, we can see that heavy oil recovery will increase firstly then decrease as the mass ratio of air and steam increases. When the mass ratio of air and steam is 2:32, the oil recovery ranks the highest, which is up to 68.67%. Furthermore, temperature showed at the thermodetecter is almost the same as steam flooding. When the mass ratio of air and steam exceeds 4:32, the oil recovery factor of steam-air combination flooding is less than that of steam flooding. The temperature at the end of the sand packed tube is far less than that of steam flooding. Through numerical simulation study based on the condition of Qi40 Block in Liaohe Oil Field by CMG, when mass ratio of air and steam is 1:32, oil recovery remains the highest. However, when mass ratio of air and steam is more than 3:32, oil recovery of steam-air combination flooding is less than that of steam flooding. Since differences exist between in-door experiment and numerical simulation, the detailed results are different. However, the tendency of the heavy oil recovery varies with mass ratio of air and steam remains the same. At last, a field test of Qi40 Block in Liaohe oil field is introduced in the paper to validate the experiment and numerical research.
Investigation of the Effects of Near-Wellbore Pressure Loss and Pressure Dependent Leakoff on Flowback during Hydraulic Fracturing with Pre-Existing Natural Fractures
Authors: Pokalai K. , Haghighi M. , Sarkar S. , Tyiasning S. , Cooke D. 
Published: October 2015

Abstract
It is generally believed that the incomplete return of treating fluids (flowback) is a reason for the failure of hydraulic fracturing and it is associated with poor gas production. Capillary effects and fracture face skin are known to be the main parameters that limit flowback in tight gas sands. However, near-wellbore pressure loss during the main operation of hydraulic fracturing and its effects on flowback are not well understood.
In the case of pre-existing natural fractures in a reservoir, near-wellbore pressure loss is high mainly because multiple fractures with tortuous paths are often created. Also, it is believed that this tortuous path causes shear dilation in natural fractures and opens the closed fractures. As a result, there is a large amount of pressure dependent leakoff. Therefore, pressure dependent leakoff has both positive and negative impacts. It can increase rock permeability and at the same time it can cause a high near-wellbore pressure drop. Hence, near-wellbore pressure needs to be reduced in order to have better proppant placement and maximize the fracturing fluid flowback.
For this research, several hydraulic fracturing treatments in the Patchawarra formation in the Cooper Basin, South Australia have been studied. There are some pre-existing natural fractures in our case study. The bottom-hole treating pressure has been analysed with 600 psi of near-wellbore pressure loss causing a low percentage of proppant placement. We constructed a 3D hydraulic fracturing model coupled with multiphase flow simulation for the prediction of flowback of water and gas production.
Several injection fall-off tests were first interpreted and found that the leakoff is pressure dependent. Our simulation has shown that high near-wellbore pressure loss has an impact on the effectiveness of the fracture treatment. This results in a shorter fracture length and low pressure distribution inside the fracture that leads to a low recovery of fracturing fluid. As a result, we have successfully provided recommendations for best practice to reduce near-wellbore pressure loss.
Development Optimization of a Marginal Tight Oil Field in Songliao Basin: Innovative Integrated Solutions to Overcome Challenges in Onshore Horizontal Well Construction
Authors: Wang Rui , Cai Min , Sun Guoqing , Wang Chao , Zhou Hongmei , Liu Xingdong , Wang Fei , Yang Bin , Li Shuzhong , Hu Zhong , Ou Rongna , Wu Kai 
Published: October 2015

Abstract
Daqing oilfield located in onshore North China has been produced for over 56 years. Most of the primary oil was produced from conventional formation. With ongoing of exploration and development, the unconventional resource development plays a key role in maintaining stable production. The reserve of tight oil is more than 1 billion ton in the central depression area of North Songliao Basin, accounts for about 40% of unexploited reserves. However, there are following challenges for developing tight oil, such as the dense lithology, complex sand distribution, lower production with vertical well development and ultra poor profit need to be overcome.
Multidisciplinary study was conducted to focus on formation evaluation and horizontal well planning optimization. A new horizontal well construction was launched to optimize the tight oil development at the beginning of 2014. Meanwhile, advanced azimuthal LWD, with the ability to map the distance to the multiple boundaries such as the oil-water-contact (OWC), the top and bottom of the reservoir structure, was selected as the fit-for-purpose application and to enhanced reservoir understanding. In combination, rotary steerable system (RSS) was selected to improve drilling efficiency and deliver smooth trajectory control.
This integrated fit-for-purpose technologies proved the value in its utility by achieving the ultimate objective of drilling six pilot horizontal wells in YA block. In these wells, average 90% net-to-gross(NTG) in sweet zone, 80% improvement in drilling efficiency and initial average productivity after fracturing is around 5 times of vertical well's.
The successful application of the integrated development strategy in this complex tight oil field will lead to outstanding production, increasing the ultimate recovery and well economics. The authors believe this approach and techniques could effectively address the following tight oil development in Songliao basin.
A Novel Selective Fracturing Proppant Applied in Daqing Oilfield
Authors: WanFu Zhou , ZhongLian Han , Gang Cao , Xin Wang , QingGuo Wang , WenJiang Chen , QingSong Li , JingMei Wang , Yang Han , HaiRong Fu 
Published: October 2015

Abstract
In the later stage of development, most oilfields faced high water cut issue after treatments. Meanwhile, how to effectively control oil wells water breakthrough after fracturing so as to increase oil production has become a big challenge for production engineers. This paper introduced a novel selective proppant which can effectively block water from entering well bore after fracturing.
Based on "eggshell principle" and interfacial tension theory, this novel proppant was developed with a new monolayer strong hydrophobic interface treatment technique. This special processing technique could not only reduce the proppant's flow resistance of oil, but also increase its flow resistance of water. As the result, this novel proppant showed the characteristics of excellent lipophilicity and hydrophobicity as well. Experiments indicated that oil water diversion ratio of selective proppant was greater than 1.2, while the ordinary proppant was less than 0.7. The oil wettability index of selective proppant was greater than 0.8, while the ordinary proppant was less than 0.3. The main characteristics of this supporting agent was small apparent density, low broken rate, and high flow capacity. The proppant surface is oil wet, which has the characteristics of oil increasing precipitation. Experiments showed that the seepage velocity of water in selective proppant was obviously lower than in quartz sand, selective proppant with water resistance.
Field test was carried out in 11 wells with selective proppant fracturing. A group of conventional fracturing wells were selected as contrasted wells with similar reservoir and operating conditions. After fracturing with novel proppant, the average water cut of producers was decreased by 7.2% per well, the average oil production was increased by 6.3 tons per well, and the average valid fracturing a period was 14.1 months. As for contrasted wells with conventional fracturing proppant, the average single well water cut decline was only 0.4%, the average single well daily oil 3.1 tons, an average period of only 5.8 months.
The novel proppant showed remarkable advantages in improving oil production and decreasing water cut. This technique has a great future for mature oilfield development.
Estimation of IFT Reduction by a Biomass Material and Potential of Its Utilization for EOR
Authors: Sugai Yuichi , Komatsu Keita , Sasaki Kyuro 
Published: October 2015

Abstract
Surfactant injection is one of the most effective EOR techniques. Chemical surfactants however pose a few problems such as their high cost and low-degradability. We study on the utilization of biomass such as agricultural fertilizer mainly comprising the residue of squeezed beer yeast for EOR as an alternative of chemical surfactants because crude oil can be completely miscible with the fertilizer solution. The fertilizer can be stably supplied at a low cost because it is a waste of beer brewing industry and is only used for an animal feed additive so far. Its retail price is approximately 1 USD/kg in Japan.
We semi-quantitatively estimated the interfacial tension (IFT) between the fertilizer solution and crude oil by the oil displacement test. Concentration of the fertilizer was varied between 10 to 50 g/L. The fertilizer solution to which sodium chloride was added at a concentration of 10 to 40 g/L was hydrothermally treated at 60, 80, 100 or 120 ºC for 10, 20, 30, 45 or 60 minutes respectively before the tests. The fertilizer solution to which crude oil was added at a ratio of 1 % was also hydrothermally treated at 120 ºC for 20 minutes. Solution of surfactin which was a commercial biosurfactant was used as a standard of the IFT.
The IFT was reduced with the decrease in salinity and increase in concentration of the fertilizer and temperature of the hydrothermal treatment. Time of the hydrothermal treatment was preferably 30 minutes or less for the IFT reduction. The capability of 50 g/L of fertilizer solution to reduce the IFT was almost same as the capability of 0.2 g/L of the surfactin solution. Because the fertilizer solution comes into contact with residual oil under high temperature in oil reservoir, IFT between the solution and crude oil can be expected to be reduced in-situ.
Core flooding experiments were carried out by injecting the fertilizer solution after the water flooding as the primary oil recovery. 1.2 % of original oil in place was additionally recovered by injecting 50 g/L of the fertilizer solution after the water flooding.
The fertilizer should be biodegradable because it is a microbially-derived substance. In addition, because the IFT reduction was observed after the hydrothermal treatment of the fertilizer solution, the fertilizer should be effective even in the reservoir whose temperature is high such as 120 ºC at which chemical surfactants may be deactivated. From those results, the injection of the fertilizer solution can be a promising EOR which has both high cost performance, low environmental load and high versatility.
A Comparison of Frac Pack and High Rate Water Pack in Multizone Single Trip Completion in Mahakam Offshore Block
Authors: Muryanto B. , Lavoix F. , Anashkin A. , Jatikusuma R. , Sinaga H.A. , Maharanoe M.I. , Nusyirwan A. , Hashim S. 
Published: October 2015

Abstract
The Mahakam offshore block consists of three fields, the Sisi-Nubi, Peciko, and Bekapai. Traditionally, most of the wells were completed with high-rate water packs (HRWPs) with good sand control and acceptable productivity. Frac packs (FP) were introduced to improve completion skin, helping ensure longevity of sand control and maximizing recovery. However, considering the unique context of Multi Zone Single Trip gravel packs (MZ-STGP) deployed in the Mahakam and reservoir challenges, the advantages of FPs were carefully reviewed and the design adapted accordingly.
Pumping results from more than 250 zones of HRWP are reviewed. Key parameters, such as blank pipe (BP) coverage and net pressure, are analyzed. HRWP productivity results are compared with 22 zones of FPs performed to date. Apart from productivity analysis, operation time is assessed to determine the merit of FP method. The classic FP parameters, such as fracture length, height, and packing factor are also examined. Special context from the Mahakam offshore fields with tight spacing between zones and presence of water contact nearby along with soft reservoirs and low stress barrier are considered in terms of assessing FP and HRWP. Difficulty to design Tip Screen Out (TSO) fractures and controlling height growth is also analyzed.
The study reveals the merit of performing FP and provides a recommendation for when to use HRWP or FP in conjunction with MZ-STGP completions. General recommendations of pumping design for both HRWP and FP are also established.
Equilibrium Acid Fracturing: A New Fracture Acidizing Technique for Carbonate Formations
Authors: Tinker S. J 
Published: October 2015

ABSTRACT
The equilibrium acid fracturing technique has been developed to stimulate wells in the Wasson San Andres Denver Production Unit. This new treatment technique maximizes acid contact time with the fracture faces while allowing control of the created fracture dimensions. Maximum acid contact time is essential to create highly conductive etched pathways on the fracture faces of cool dolomite formations which react slowly with acid. Control of fracture dimensions is important in the Denver Unit San Andres because fractures tend to grow uncontained in at least one vertical direction and the oil column is bounded by permeable gas bearing intervals above and permeable water bearing intervals below.
Using this technique, a fracture of desired dimensions is first created by injecting acid at fracturing rates. The volume of acid required to create the desired fracture dimensions is determined by a two dimensional fracture geometry program using design parameters determined from mini-frac testing and laboratory testing.
Injection is then continued at reduced rates which maintain equilibrium with the fluid leak-off rate from the created fracture faces. By maintaining equilibrium between injection and leak-off, the created fracture can be held open without significant further fracture extension.
Equilibrium is achieved in the field by maintaining the injection pressure below the fracture extension pressure, but above the fracture closure pressure determined by mini-frac testing.
The background and theory of this technique will be presented in this paper along with design procedures, field examples, results, and conclusions. A comparison of the results of the equilibrium acid fracture treatments to the other acid stimulations performed in the Denver Unit is also shown.