bluuebunny/crossref_metadata_2025_split huggingface dataset:
Breaking the Barrier of Flow Simulation: Well Placement Design Optimization with Fast Marching Method and Geometric Pressure Approximation
Authors: Zhang Jianye , Huang Lan , Liu Min , Cui Xiaofei , Jiang Zhixiang , Bahar Asnul , Pochampally Saikiran , Kelkar Mohan G. 
Published: October 2017

Abstract
This paper presents the implementation of a novel approach for efficient well placement design based on the dynamic characteristic of the reservoir without the need to run flow simulation. The approach uses State-of-the-Art Technology called the Fast Marching Method (FMM) coupled with Geometric Pressure Approximation to define a Dynamic Reservoir Quality Map. This map is also referred to as the Depletion Capacity (DC) Map. It provides the mapping of future potential locations to further deplete the reservoir.
The DC Map is generated by calculating 4 important factors, namely Pore Volume, Mobility of the Hydrocarbon, Reservoir Energy, and the Undrained Volume of the reservoir. The major breakthrough in using this technology is the ability to estimate the pressure distribution (i.e., reservoir energy) and drainage volume (i.e., to estimate the undrained volume) efficiently. These are the 2 factors that are difficult to obtain without conducting traditional flow simulation. The two aforementioned factors were obtained by calculating the FMM diffusive time of flight which can be related to the pressure drop by the Geometric Pressure Approximation theory. Thus, in effect, this calculation represents a pseudo-simulation, which is orders of magnitude faster than conventional simulation. The technique is applicable for both fine scale and coarse scale models with large number of realizations representing geological uncertainties. This approach works well in capturing the primary depletion phenomenon.
In this paper, we demonstrate the evaluation of existing well placement of an actual developed field, with 16 wells, located in Tarim Basin, West China, by comparing it to a new design. Additionally, the method is also used to propose future locations for infill drilling. The study is motivated by the big challenges faced when drilling a well at a depth between 6800 m–8000 m. Optimum well placement has the potential to drill optimum number of wells to produce the same reserves.
The new design was created with a scenario where 5 exploration wells that been put into production for a couple of years to represent the early depleted condition. The results show the optimum design can be achieved with only 12 wells. A saving of 4 wells compared to the existing well pattern. This is a significant saving considering the drilling challenges.
For the infill drilling, the study shows that for this reservoir, adding more wells may not be beneficial from the ultimate recovery point of view but production can be accelerated by drilling up to 2 more wells at the best potential locations as suggested by the DC Map. Best of all, the proposed method optimizes the locations very quickly.
A Simplified and Robust Approach to Integrated Asset Modeling for Performance Forecasting of a Large Dry Gas Field in East Coast of India
Authors: Kumar Amit , France Brandon , Talukdar Ramen 
Published: October 2017

Abstract
A simple yet accurate approach to integrated asset modeling of a complex deepwater dry gas field in the east coast of India is presented here that involves the use of a multi-tank material balance model.
The field shown here has wells having multi-zonal completion with multiple contacts and perched water. Matching well-wise watercut with multiple water breakthrough events while simultaneously obtaining a good match of declining well pressures has historically been a challenge in this field. In this paper a novel and robust solution to this problem of simultaneous water cut and pressure matching has been presented through the combined use of fractional flow curves and analytical water breakthrough matching. Issues with the modeling of the pressure drop of pipelines and wells which are starting to liquid load and are flowing in the unsteady-state regime have also been addressed in this IAM model.
A multi-tank MBAL model was built using partially connected tanks which was enhanced with the use of compaction correction to both permeability and inter-tank transmissibility. Well-wise fractional flow curves were used for water rate prediction. Wells, chokes and pipelines were modeled and history matched to field data in GAP. Pressure drop calculations were calibrated to loading curves generated from OLGA. A description of the history matching and production forecasting through the IAM model and its use for evaluation of production optimization strategies such as the use of velocity strings has been shown.
Evaluating Natural Fracture Effectiveness to Optimize Well Stimulation Method for HTHP Tight Gas Reservoir
Authors: Yang Xiangtong , Xu Jianhua , Teng Qi , Abbott William E. , Zhang Yang , Zhao Meng , Zhang Chen , Gu Xiao , Li Wei , Fan Wentong 
Published: October 2017

Abstract
Keshen gas field, located on the northern margin of the Tarim basin, Western China, is an unconventional sandstone tight gas reservoir with extreme reservoir conditions: ultra-deep, low porosity, low matrix permeability, high temperature and high pore pressure. In order to gain economic production most wells should be stimulated to enhance single well performance. Previous studies show that natural fractures (NF) play the most important role on productivity. Detailed studies on block KS2 found that well performance is controlled by the intersection angle (θ) between NF strike and direction of the maximum horizontal stress. When the interaction angle is small, well productivity is good. Otherwise, well productivity is poor. Based on this conclusion, different simulation options were proposed: 1) Acid hydraulic fracturing for wells with small angle, and 2) Proppant hydraulic fracturing for wells with big angle. New problems were meet when we applied this rule to other blocks, such as block KS8. In this block most wells reached a good production even if the intersection angle is big (&gt;40°). Therefore, it is unreasonable to determine stimulation options based on the intersection angle for these wells.
In order to establish alternative stimulation options, deeper analyze focused on natural fractures has been conducted. First, the tectonic history was studied to understand the NF creation and it was found that natural fractures are associated with two main tectonic phases. Most of the natural fractures developed during the earliest phase are infilled by calcite or shale(set 1), Whereas NFs developed during the last phase are open or partially open, have high permeability and are contributing to the production(set 2). Wells with reticular NFs have two sets of NFs and have high production. Advanced analyses of borehole images, including fracture classification according to the tectonic events, fracture density, and intersection angle computation, allowed us to create four main classes: class 1: presence of reticular fractures, class 2: parallel fractures with small intersection angle, class 3: parallel fractures with big intersection angle, and class 4: no natural fractures. New stimulation options were proposed based on these four classes: class 1: acidizing without hydraulic fracturing, class 2: acid hydraulic fracturing, class 3: proppant hydraulic fracturing, and class 4: it is hard to get economic production for these wells, even if the proppant hydraulic fracturing is operated.
These new stimulation options have been applied in new blocks of Keshen tight gas field and provide a practical way to optimize the stimulation, to ensure well performance, and to reduce the cost associated with multiple stimulation phases in this tight gas field.
Review: Uncertainty Analysis and Design Optimisation of Gas-Condensate Fields
Authors: Abdul-Latif Benson Lamidi , Hikmahtiar Syouma , Edem Tsikplornu Daniel 
Published: October 2017

Abstract
Contrary to conventional reservoir development, uncertainty analysis and design optimization of gas-condensate fields have received less attention due to a general assumption that oil field production data analysis and computational methodologies and techniques can be applied to gas-condensate fields. Understanding the uncertainties and performance of gas-condensate reservoirs is vital to predict production profiles. This paper investigates and reviews published literature of the most essential factors affecting gas-condensate production in a domain of real data from gas condensate fields.
In this paper, uncertainty analysis was performed using third and fourth order factorial design (Box Behnken technique) on a domain of gas-condensate fields' data to identify key factors affecting the production of condensates from heterogeneous and ultra-low permeability reservoirs. Objective functions and response surface models for gas-condensate reservoirs were optimized as functions of cumulative condensate production incorporating the effects of condensate banking in gas condensate fields. A second-order surrogate model was designed by regressing compositional results and then optimized as functions of the ten main factors affecting gas-condensate reservoir production.
Uncertainty analysis of gas-condensate reservoirs revealed that condensate blockage radius, reservoir permeability, well spacing, reservoir thickness; compressibility, initial pressure; fracture spacing and initial condensate saturation were the most significant parameters affecting condensate production. Validation results revealed that the surrogate models of gas-condensate recoveries could be used with good confidence to predict condensate values in heterogeneous and ultra-low permeability reservoirs.
Cost Effective Method to Maintain Integrity of Non Productive Asset: Case of Tunu GTS-H Preservation
Authors: Marzuki I. , Junaedy H. 
Published: October 2017

Abstract
In the current low oil price context, operation of low productive asset is very challenging, particularly to maintain the integrity while production deliverable is not significant. This situation is experienced in Tunu Gathering and Testing Satellites (GTS) operation, where 4 out of 39 GTS have been confirmed low producers since the last 4 years. For optimization scheme, preservation was proposed where GTS-H was selected as pilot case. This paper will focus on detail assessments that carried out during preparation phases, including stakes review, preservation scheme definition, safety, cost benefit analysis, and overall impact to operation.
Result of GTS-H pilot project confirmed that preservation is a cost effective method to continue operation of non productive asset. Project management approach is an applicable method to execute low cost preservation, which is recommended to be applied to other low producer facility. Comprehensive review at preparation stage is outmost important, not only cost – benefit review, but also all operational aspects, most importantly safety and integrity related. Changes in operation scheme after preservation shall be assessed properly and justified with risk base analysis.
The Characterisation of Differential Depletion in a Thinly Layered Coal Seam Gas Reservoir Using Packer Inflation Bleed Off Tests PIBOTs
Authors: As D. van , Bottomley W. , Furniss J. P. 
Published: October 2017

Abstract
The coal seam gas (CSG) developments of the Surat Basin in Australia are a world-first in CSG-to-LNG.Methane is extracted from thinly-bedded, shallow Jurassic coals by de-watering the coal fracture network to promote desorption of gas from the coal matrix. Drill stem tests (DSTs) or wireline conveyed tests (MDTs/FRTs) are conducted to collect permeability and pressure dataas part of specialised data acquisition in newly drilled wells. Reservoir depletion in the various coal layers is currently measured bydedicated pressure monitor wells located offset to producing development wells; however, the number of these wells is limited. This paper presents a new, inexpensive approach tomeasure seam-level reservoir pressure depletion using Packer Inflation Bleed Off Tests (PIBOTs).
Using an existing dual packer drill stem test (DST) tool, formation intervals as small as 1.5 metres can be isolated, allowing individual coal seam measurements to be made. The packer inflation bleed off test (PIBOT) uses the overbalance of mudweight to drive the equilibration and measurement of reservoir pressure between the packers. Supercharging has not been observed in these high permeability coals and no fluid is produced or injected during a PIBOT, which significantly reduces the rig time required. The high permeability in much of the Surat coal allowstypical pressure stabilisation times of 30-60 minutes, meaning that up to 14 intervals in a given well can be tested in a single rig crew shift.
As part of an infill drilling program in areas offset to existing production, QGC has conducted several PIBOT surveys to date. The significant advantage of PIBOTs over DSTs is the reduced cost and rig time. In the first campaign, 81 PIBOTs (9 wells) were performed at the same cost as 12 DSTs (4 wells). The opportunity to collect this increased number of reservoir pressure data points for characterisation brings significant value. The results have confirmed, with high confidence,that significant differential depletion has occurred between the upper and lower seam layers in producing areas of the Walloons and the consistency of these depletion patterns across very large areas. The results of these novel formation testshave implications for gas recovery estimates, and thelocation and design of future wells. The reservoir model can also be validated at a more granular level by data that captures the non-virgin conditions at a distance from producing areas.
Target Cost Setting Model for Indonesian PSC amid Low Oil Price
Authors: Nugraha Candra 
Published: October 2017

Abstract
Target Cost Setting (TCS) objective is set up for required capital and operating cost for development of products at desired profit margin (Cooper, 2001). Dropping oil price recently which predicted longer (Bloomberg, 2016) will lead to a shortage in production by year 2035 (Woodmac, 2016). The various concepts for oil and gas development have to be analyzed in order to sustain the growth of production while maintaining an economic threshold limit during this low oil price period. The preferred concept development shall be achievable by doing reverse engineering (top down estimate) at the early stages of oil and gas life cycle.
The driving idea behind this method is expediting the project framing and front end engineering process as well as maintaining continuous exploration and development within limited budget by allowing some "low hanging fruit" projects, while still obtaining the desired profit margin. The TCS model is working in the existing fiscal arrangement for any particular field and subsurface definition. The TCS simulations are performed by using available tools for cost estimation and economic models.
Drilling of HPHT High Angle Well in a Fractured Reservoir-A Case Study
Authors: Al-Mohailan Mohannad , Sounderrajan Mahesh , Al-Azmi Salah , Patil Dipak Pralhad , Nellayappan Karthik , Aljarki J. 
Published: October 2017

Abstract
Kuwait has been drilling and producing from the deep, sour Jurassic reservoirs during the past 30 years. Drilling high angle wells / horizontal wells can provide a means to intersect possible oil bearing fractures besides extending the drain hole length for increasing productivity. The wells drilled to these prospects are challenging because of HPHT conditions, narrow mud weight window and sour gas. The Jurassic reservoirs itself exists below a deep high pressure formation G bearing multi Salt-Anhydrite sequences.
The Jurassic wells are typically based on big bore well design with the final hole size ending in 6 ½"/6" hole size. The well constructions typically comprise of seven casing policy and requires 15 K well control equipment. It is imperative that surface/intermediate casing strings are run to the maximum depths possible in order to reach well TD in the planned workable hole size. The isolation of formation G with the planned 10 ¾″ casing is essential to drill and complete the wells efficiently.
In well A-14, due to complex geology, the required formation top could not be ascertained. The well construction was altered to case off the unexpected recurrent high pressure section which led to downsizing of the available hole sizes to drill upper and lower Jurassic reservoirs in slim hole. As the planned horizontal of required length was deemed infeasible in 4 ½" hole size, the well was converted to an high angle well. The unusual presence of fracture corridor with high pressure hydrocarbons below formation G posed a series of challenges. The drilling window was extremely narrow between 18.4-18.6 ppg where drilling had to be continued either with ECD or under losses with high density fluid of 18.5 ppg. The requirement to achieve the well profile with known limitation of directional drilling tools to use LCM pills was planned with due controls. On many occasions, the removal of ECD resulted in gains and many well control operations had to be resorted to including bull heading during trips.
The well was drilled to TD and the upper Jurassic reservoir tested successfully. The paper will present lessons learnt, practices employed to drill with losses and gains, tripping considerations, fishing complications, slim hole drilling challenges, improvisation of drilling and cementing practices in near total loss situation and directional drilling techniques adopted. This would then provide the basis for future optimization in these types of wells.
From Sandface to Processing Plant, an Integrated View of an Operating Envelope in a Gas Condensate System
Authors: Sueiro. M , Lanchimba. A , Bilbao. C , Tavara. R , Canchucaja. R , Espinoza. P Repsol 
Published: October 2017

Abstract
What are the formations production limits? What are the technical limits that define the operating envelope of Wells, pipelines, and facilities of existing and those that are under construction? Are these limits defined on steady state only? Also, what about transient? How can the system be operated efficiently?
To answer these questions, an integrated study was made to cover all the aspects mentioned in the previous questions, and to determine the operating envelope in both steady state and transient of all the elements (Wells, pipelines, slug catcher, etc.) of FieldAB gas and condensate production system. This system is located on a remote location in the Peruvian Jungle.
This study was performed in three stages. The first stage implied to make Well models of the existing producers and match the output with the results obtained during Well testing at initial conditions. On the second stage, surface production facilities were added (manifold, flowlines and slug catcher)to make an integrated model. This model output was matched with initial conditions (production startup) and the conditions after two and half years of production. Finally, on the third stage, the under-construction installations models were added with information from EPC contractor.These models include: Three new producers and associated surface facilities, two new pipelines and a slug catcher (compression station entry). All the previously mentioned models were built in OLGA.
Once the integrated model was made, a methodology was developed to determine the technical limits of each element of the production system.The parameters that will to be described are part but not all the parameters evaluated. For each Well the followingswere evaluated: Liquid Loading, Maximum Production Rate (Erosional Velocity), and Maximum Opening Speed depending on the liquid content of each Well to avoid slugs that could not be handled by the slug catcher. For each pipeline, the Maximum Production Rate to avoid Erosional Velocity, and Minimum Rate to avoid instability, were evaluated.
Results give flexibility to operators to know between which limits they can operate the production system elements in transient and steady state, and on what parameters they must be focused on while making a maneuver or on normal production.
Integration is the keyword of this project. A production system must be analyzed as a whole, not only analyzing the behavior of the elements individually. This study offers an integrated view point of how to define operating envelopes and operating procedures that have the potential to optimize an asset production and improve the system elements life.
Integrated Work to Deliver 4,000 BPD Oil from Gas Dominant Field: A Case History from Rejuvenated Brown Field Gas Lift Development
Authors: Muhammad Kahfie Rizky , Kurniawan Farid , Yahya Musyoffi , Oscar Edy I Ketut , Izwardy Saesarian 
Published: October 2017

Abstract
The brown field, Mutiara, has been producing for more than 25 years where its reservoirs consist of thousands of lenses as a result of the deltaic sedimentation. Operated by VICO Indonesia, aggressive drilling program was implemented to arrest production decline and to increase additional oil reserves from existing and newly discovered reservoirs. Current practice of producing natural flow will not be sufficient to recover oil from small lenses reservoir. Therefore, integrated works need to be implemented for the oil development in this field.
Splitting focus from gas to oil production is long journey to walk. Major facility upgrading was needed to eliminate gas lift system "blank spot". Additional compressor was also needed to maintain gas lift pressure distribution in southern remote area.
A thorough project planning and procedure are established to ensure optimum field production. Oil zones evaluations followed by prioritization are discussed with well intervention and construction team. After perforation is completed, PCTGL was designed with thorough calculation. It is important to accurately measure pressure drop along gas lift line since PCTGL use single unloader valve which is sensitive to injection pressure changes.
VICO Indonesia cross function team, consisting of Resource Management, Technical Support and Operation, conducted regular bi-weekly monitor during this development phase. It was important to ensure every team carried out their respective responsibility.
Then harvest time is coming; Mutiara oil production delivered average production of 4,981 BOPD in 2016, an increase of average 2,970 BOPD than 2013. The integrated gas lift also managed base production annual decline by delivering above 4,500 BOPD for in 2015. In the last four years, VICO Indonesia also managed to produce cumulative of 5.1 MMBO oil from this project.