bluuebunny/crossref_metadata_2025 huggingface dataset:
In-Situ Stress and Fracture Controls on Permeability Distribution within Walloon Subgroup, Surat Basin
Authors: Mukherjee Saswata , Copley Jeff , Esterle Joan
Published: October 2017

The Surat Basin Coal Seam Gas (CSG) is maturing from exploration to production to meet sales targets for several Liquefied Natural Gas projects. This requires effective and predictable reservoir performance that is controlled by permeability, gas saturation and matching the well completion technique to the ground conditions. Permeability in coal has major dependence on in-situ stress and natural fractures, and these will have characteristics that vary from field scale to larger regional scale faults and folds. This study investigates the spatial and stratigraphic variability of stress and fracture orientation relative to measured permeability within the Walloon Subgroup (WSG) that hosts CSG resources within the Surat Basin.

Open file wireline data from 33 vertical wells across the eastern part of the Surat Basin are used to calculate the in-situ stress orientation and fracture distributions within the WSG. Present day in-situ stress orientations were identified from the borehole breakout and drilling induced tensile fractures. Permeability data from 13 wells are compared using the in-situ stress and fracture data from image log interpretation.

CSG reservoir permeability is, in general sensitive to the changes in effective stress and primary permeability is reduced exponentially with increasing effective vertical stress. However, this relationship does not always hold true. Permeability within the WSG is also affected by the angle between present day in-situ stress orientation and fracture or joint trends and fracture dip angle. Wells in the relatively simple structural areas with subtle faulting show higher permeability when the coal fracture trends are parallel and up to 40 degrees to the present day in-situ stress. Permeability is significantly less outside this range. Most of the high permeability zones tend to occur in the areas where there is significant rotation of in-situ stress from the regional mean stress orientation (commonly ENE – WSW). The observed stress rotation is attributed to the stress perturbations mainly from folds and faults within the Surat sedimentary succession, suggesting local structural influence on the permeability distribution within the WSG. Few analyses of permeability versus stress and fracture properties are in the public domain for the Surat Basin. This study illustrates the connection between different structural domains, stress and fractures in previously unidentified areas of oblique-slip faulting, in some cases reactivating and in others creating new features from basement through the Jurassic to Tertiary succession.
Effect of Casing Coating Materials on Shear-Bond Strength
Authors: Jadhav Rahul , Palla Venkata Gopala , Datta Amlan , Dumbre Maithili
Published: October 2017

A well-executed cement operation is fundamental for successful zonal isolation. One method used to confirm the success of a cementing operation is cement bond-log (CBL) analysis. Various factors contribute to good bond strength at the casing-cement interface; a better shear bond helpsminimize the risk of communication between different zones and also maximize production by avoiding undesirable fluid diversion during well intervention. To enhance shear-bond strength, a thin layer of coating material can be applied on the external surface of casing before running itin the well. Variouscoating techniquesare available, such as spraying, dipping, or simply brushing. Polymer emulsions, thermosetting polymers, and inorganic-based coatings can be applied. This paper studies the effect of various coating materials on shear-bond strength.

A coated casing sample was concentrically placed inside another largercylinder and cured after filling the annular space with cement slurry. Once cured, the shear-bond strength was experimentally measured using a hydraulic press. The results obtained with various coating materials are compared to those from an uncoated control sample.

The shear-bond setup was prepared with neat standard cement slurry and cured for 3and 7days for testing. Three different types of casing coating wereevaluated for enhancing shear-bond strength—inorganic-based, aqueous polymer emulsion, and thermosetting resin. All three coatings providedenhanced shear-bond strength compared to the control sample. The inorganic-based coating almost doubled the shear-bond strength. The aqueous polymer emulsion coating increased shear bonding by approximately 30%. Finally, the thermosetting resin coating resulted in a much smaller increase in shear bonding compared to the other treatments; however, it was observed to provide better resiliency while applying loads during testing.

A thin layer of coating onthe entire length of a casing column does not significantly increase costs. On the contrary, significant value is providedthrough better shear-bond strength and potential corrosion resistance. Therefore, this practice can eliminate the necessity of remedial treatments later. Additionally, applying the inorganic-based coating on the outer surface of casing pipe provides additional bond-strength between the cement and casing, minimizing the risk of inner debonding.

The coating application process is operationally simple and can be readily implemented, and it provides a low-cost, dependable barrier. In addition to providing better bonding, coating can also inhibit corrosion and increase the life of the tubular.
Refactoring Carbonate Reservoir Architecture through Real-Time LWD Measurement
Authors: Hassan N. A. , Syailendra A. A. , Hanalim L. , Santoso G. I. , Alang K. A.
Published: October 2017

X Field is a carbonate platform setting in Central Luconia, Malaysia. The field faced declining trend of gas production due to early water rise. Seismic attribute shows that the rising water was assumed to be related to the water being drained through crossflow into the possible karst feature, which may have acted as conduit located near the existing production well bore. Two horizontal infill wells were planned in this field with the objectives to accelerate the gas production, and to investigate the uncertainty on the current gas water contact (GWC) movement, karst feature and fracture identification in single run LWD. The horizontal well placement strategies were set in different workflows as some key reservoir parameters are still uncertain. Several scenarios were made based on real-time reservoir characterization and observation, then they were translated into different production performance profiles. To achieve those well objectives, a new technology approach was proposed that consisted of the latest reservoir mapping while drilling technology with the capability to map the reservoir structure and fluid contact within 35m depth of investigation. This was combined with the full suites of log measurement including neutron, density and sonic data for secondary porosity measurement to support the real-time petrophysical and well placement decision making. The two horizontal infill wells were planned to stay close to the top of carbonate and to avoid the water contact as much as possible in order to optimize the gas production. The second well would depend on the first well reservoir observation result. On this case study, the application of reservoir mapping technology while drilling has successfully demonstrated the well placement as close as 7m TVD below the reservoir roof and mapping the gas water contact at 30m TVD below the trajectory. The actual GWC was detected 25m shallower than prognosed, so the finding of this first well has led to the decision to eliminate the drilling of the second well, which resulted in a cost saving of more than USD 20 million. Other than that, the qualitative result from reservoir mapping tool provided a new understanding of carbonate reservoir modeling, which confirmed the interpretation, current GWC and reservoir heterogeneity characterization both vertically and laterally. This strategy could be replicated in other carbonate reservoirs to delineate current gas water contact without physically penetrating it. Karst and secondary porosity interpretation were used for completion optimization and to maximize the production.
Integration of Time-Lapse Pressure Transient Analysis in Reservoir Characterization and Reducing Uncertainty of Initial Gas-in-Place Estimation: A Case Study in Gas Condensate Reservoir
Authors: Rushatmanto M. , Sianturi J. , Suwito E. , Priskila L. M.
Published: October 2017

Tunu is multilayer gas field operated by Total EP Indonesie in Kutai Basin, which produced since 1990. It consists of thousands of gas-bearing sandstone reservoirs; spread over 2000 meters of vertical gross thickness. The depositional environment is deltaic, dominated by distributary channels and mouth bars.

Estimation of Initial Gas In-Place (IGIP) is important for gas field development. Well testing by recording bottom-hole pressure to conduct Pressure Transient Analysis (PTA) should not be limited to classical approach of determining permeability and skin parameters. Moreover, integration of time-lapse PTA can be very useful to reduce uncertainty of IGIP estimation as well as to access reservoir dimension when all reservoir boundaries are reached.

The advantage of time-lapse PTA with material balance model over classical P over Z (P/Z) method is capable to model reservoir dimension using either analytical or numerical. Other advantage is able to detect any transmissivity change due to fluid contact such as Gas Oil Contact (GOC) or Gas Water Contact (GWC). Estimation of IGIP using PTA from well testing is possible to be carried out before the well put on production or afterward, conversely P/Z method requires the well to be produced for quite some time to have pressure depletion.

DST survey in most of cases is carried out with limited duration in order to minimize operational cost related to rig time. Therefore conducting another well testing after well completion is useful when survey duration is more flexible as no time limitation associated to rig time. Furthermore well testing duration can be designed accordingly until all boundaries are reached in order IGIP can be estimated and reservoir dimension can be modeled accordingly.

This paper demonstrates the added value of time-lapse PTA in gas condensate reservoir. The integration of time-lapse well testing with the incorporation of one year of well production is considered as a good practice in reducing IGIP estimation and accessing reservoir dimension. Interference test was done to access reservoir connectivity between two wells where seismic interpretation shows different channel body. Based on connectivity between wells that penetrate channel reservoir 4d, material balance PoverZ (P/Z) to estimate Connected Gas In Place (CGIP)can be carried out accordingly.
Supervisor Performance Assessment Method Based on AHP
Authors: Zhang Shaohui , Wang Shuai , Wang Ling , Liu Xiaochen , Teng Xinxing
Published: October 2017

In the process of petroleum exploration and development, the front-line supervisors have played an important role in ensuring the operation quality and safety. The supervisor performance assessment is the core of supervisor management. However, the traditional performance assessment only focuses on the written test and interviews, with single standard, more qualitative judgment and less quantitative analysis. The performance assessment results are greatly influenced by human factors, being lack of scientificity and fairness.

In order to further improve the supervisor performance assessment system, the performance assessment hierarchical structure model for the supervisor has been established with the use of analytic hierarchy process (AHP). The work capacity, work performance, professional ethics, skills examination, daily training and coworker evaluation are taken as assessment criteria. The weight of each criterion is determined by establishing the judgment matrix, checking the consistency and calculating the weight. In addition, the supervisor performance assessment management software has been designed, which will be conducive to the application of this performance assessment method in oilfields.

The new performance assessment method for the supervisor not only realizes the combination of qualitative analysis and quantitative analysis, but also realizes the combination of dynamic evaluation and 360 degree feedback. Based on the performance assessment results, the level-to-level management of supervisor has been realized. In addition, the salaryis directly determined by the performance assessment results. Moreover, the supervisor is selected and assignedaccording to the performance assessment results.

The establishment and application of supervisor performance assessment system provide a more reliable basis for the supervisor management and selection, and realize scientific and reasonable assessment of the supervisor.
Investigation on the Failure of the Bearing Mechanisms of the Marine Turbine on an FPSO Operating in Vietnam Waters
Authors: Vijayaraghavan Vijay
Published: October 2017

Marine turbine bearings are very susceptible to failures through number of different mechanisms such as wear, fatigue and mechanical damages due to the conditions it operates in. The failure of this particular thrust bearing lead to the whole turbine being shut down as a result sizing of the shaft and In this study failed part of a thrust bearing related to a 20.4 MW GE LM 2500 Marine Gas turbine was examined and findings was presented below.

Large amounts of surface cracks, noticeable changes of the failed surface with significant escalation of surface hardness were the main results. The studies revealed that the bearing part coming loose and shifting into dis-proponate clearance producing relative displacements under cyclic gradient loading. This condition grossly reduced the service life of turbine journal bearing via failure through fretting fatigue mechanism.
Surface Controlled In Situ Gas Lift for Appraisal of Oil Reservoir in a Gas Well
Authors: Hamza N. , Baghdadi F. , Ibrahim S. Y. , Madon B.
Published: October 2017

Gas lift is an artificial lift technique, using injected gas from the tubing-casing annulus to aerate the fluid column to reduce its density. The formation pressure is then able to life the fluid column and forces the fluid out of the wellbore. The same application can be provided through many different deployment strategies. The most common deployment would be through a downhole gas lift mandrel and valve, with gas supplied by a surface gas compressor. The gas lift rate is mainly controlled by the compressor discharge pressure, well pressure as well as the orifice size of the operating gas lift valve.

An alternative deployment available is called Auto Gas lift (AGL). The main difference is on the gas lift source, where AGL taps into an existing gas reservoir. The gas lift rate is controlled by an Inflow Control Valve (ICV) which operated through a hydraulic line.

In an existing well, AGL may still be pursued even though there is no possibility of deploying an ICV. Instead, once perforation to the gas reservoir is made, a tubing patch with a preinstalled gas lift valve can be installed. The main limitation for this application would be on the tubing patch installation, the resulting ID restriction as well as the operation required to change the injection rate or to close in the gas interval.

This paper will discuss the first application of AGL with surface control to appraise an oil reservoir in an existing gas well. The application eliminated requirement of coil tubing deployed 13Cr tubing patch and gas lift valve installation. The methodology used to evaluate the application is described and its results discussed and compared to the actual well result.
Smart Nanoparticles for Conformance Improvement in Waterflooding
Authors: Temizel Cenk , Putra Dike , Zhang Ming , Moreno Raul
Published: October 2017

Per recent analyses, in the near future, over half amount of the oil extracted globally, will require some form of enhanced oil recovery (EOR) techniques. Existing literature and historical investigations suggest that in oil reservoirs having viscosities between 10 – 150 m.Pa.s, there is a significant potential for tertiary recovery through the application of polymer flooding. For reservoir oil viscosities above 150 mPa.s, the polymer pumping efficiency goes down as polymer injectivity reduces significantly with increasing injection water viscosity that are used to attain a favorable mobility ratio at such high oil viscosities. To overcome this limiting factor, in this study, we propose the use of supramolecular assemblies (SMA) that have adjustable viscosity properties. Complexation of long-chain amino-amides and maleic acid is used to make these assemblies, which allow it to have reversible viscosity depending on the solution pH level.

To maintain high injection efficiency, during pumping, SMA solutions will be kept at low viscosity values. On entry in deep reservoir or at oil contact phase, through introduction of an external stimulus the viscosity of SMA solution will be reversed to a much higher viscosity. This will allow to sufficiently improve the mobility ratio. Preliminary results from lab-scale studies have indicated that along with reversibly adjustable viscosity property, SMA solutions are also tolerant to high temperatures and salt concentrations.

Supramolecular solutions can be considered as healable polymer systems, since unlike conventional polymer they disassemble and re-assemble when exposed to high temperature and stress conditions. In such conditions, conventional polymers generally undergo degradation. Additionally, through molecular scission processes SMA solutions can also be used in highly confining environments as well as in permafrost conditions and thin zones where conventional thermal techniques are not applicable.

The objective of this work is the development of novel SMA system that have the aforementioned properties of reversibly adjustable viscosity through pH, tolerance to high temperature and salt concentrations through desired interfacial properties. Lab-scale preliminary results have shown the potential economic benefits of the use of SMA solutions on a field-wide scale. Based on the results, it must be emphasized that SMA systems have a worldwide application in oil reservoirs for EOR purposes.
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

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

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

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 (>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

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

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

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

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

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

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

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.
Extreme Underbalanced HPHT Coiled Tubing Conveyed Perforating: KN-Ultra Deep Field Study
Authors: Rosato Miguel , Bakar Mohd Farris , Azmi Fadzliana
Published: October 2017

In order to carry out the first HPHT field development offshore in Malaysia, learning from experience of HPHT operators in the North Sea, a detailed focus on lifecycle and well integrity aspect has been thoroughly emphasized throughout the well delivery phase. At an initial stage in the project, a locally conventional initial design considered the use of TCP to perforate a 7″ liner and then complete the well in open hole with overbalanced completion fluid. This solution carried several challenges that would have affected the safety of the completion process and the future integrity of the well architecture.

A different approach, in which a fully cased hole well is completed in underbalance and then perforated once the completion is installed and tested is introduced for the first time within PETRONAS. The system allowed the perforation of a 400m HPHT reservoir interval in a single run, by using a dedicated coiled tubing deployment system.

The implementation of this completion philosophy permitted to achieve the following milestones: Completion in underbalanced packer fluid, which enhanced the well architecture by reducing potential production casing failure due to extreme loads in case of tubing leak.The use of inhibited fresh water, provided an effective, alkaline fluid that eliminates the very high potential for corrosion created by heavy, high halides completion brines.Safer way to run the completion in a closed, inflow tested environment.Single perforating run, which allowed for a safer procedure for the deployment of guns. There is no deployment of guns under pressure or under exposure to hydrocarbon.If required, especially in very tight reservoirs, there is the ability to displace the well with N2 immediately after perforating (separate runs for stimulation are not required)As soon as the last gun is out of hole, the well is ready for well testing / clean out / production.

This paper covers the design, QAQC, operational and logistics aspects of the KN Ultra Deep'sCoiled Tubing Conveyed Perforating with a final section covering the challenges and lessons learned that may be used by project teams in the future.
Downhole Production Logging for Locating Water Sources in Open Hole Completion Oil Producer Wells
Authors: Yaakob Amirul Afiq , Hutamin Nurhidayah , Sa'aid Hasanah , Salleh N Hajjar , Nor M Hafizuddin , Anas W M , Setiawan Agus , Azraai M , Mariam Siti , Alam Bambang N , Iless N Afifah , Rahman M Zhafran , Amin M Farid , Mohamed Tatmimiddin A
Published: October 2017

The use of open-hole completions in the design of production wells is a particularly appealing choice for oil companies, since it can ensure huge economic advantage compared to conventional cased-hole completions. Nowadays, most operators are looking for more innovative economical well completion design. Swell packer is one of the technology that widely used in open-hole completion strategy with combination of others completion accessories. Coupling the swell packer with open-hole completion application, it makes multiple zonal pressure isolation in the following open-hole completion possible: bare foot condition, predrilled liner, stand-alone screen, open-hole gravel pack or even open-hole fracturing packing. However, few typical implications associated with open-hole completion which complicated further the well integrity and flow performance monitoring.

In 2012, 11 oil producer wells were completed in Field X with open-hole completion and installed with stand-alone screen (SAS), swell packers and double valve float shoes. First oil was achieved in April 2012 with all wells initially producing high oil rate and low water cut. However, towards the end of 2013, some of the wells started to show high water production. Production logging (PL) was conducted at Well #1 to evaluate the flow contribution and water source. It was concluded that the water was coming from the bottom of double valve float shoe. Remedial action was taken by setting a plug for water shut-off and the water rate dropped drastically. In 2015, it was decided to replicate the production/well diagnostic analysis in all open-hole completed wells. Similar results were then observed by production log (PL) and consequently, remedial action was taken accordingly.

The production log (PL) interpretation, historical production plot and surface well test results were integrated and provide the required information to determine the forward production strategy in these open-hole completed wells. This paper will share multiple case studies where water source diagnostics have been performed in open-hole completions, as well as lessons learnt and best practices throughout this process.
Automatic Control Surface Safety Valve: Low Cost Solution to Optimise Production
Authors: Moelyono S. P. , Kusuma P. F.
Published: October 2017

The best way to maintain the base production since there is no drilling, fracturing, and limited rigless activity in mature field (Nilam field) is by reactivating cyclic wells, opening or shutting the well in for certain period of time. Hundreds of string, extensive area, and short period of cycle time make ineffective job since there are limited number of operators to handle. A design of automatic system to open or close cyclic well is created to solve the problem.

This automatic system named "autocyclic" modifies well instrument system. The method is by adding a pair of pressure switches to create pressure span between pressure setting value to open and close the SSV. When the shut-in pressure reaches the open pressure setting value, the SSV will automatically open and gas can flow, when the flowing pressure decline and reach the close pressure setting value, the SSV will automatically close. Using SSV as open and close mechanism does not eliminate its main function as safety valve.

The application of "autocyclic" is optimized based on well flowing time and pressure. The value of pressure switch setting is adjusted based on the history of the well and can be optimized to get the optimum cumulative production. Due to safety reason related with plant, the well is still choked. The result is astonishing reflected from there are 7 string installed in 2016 with total gain 1.31 MMscf compared with those wells produced in natural cycle. In the first semester 2016, those wells contribute 0.1 Bcf as cumulative production. These modifications cost around $ 608 per installation that mostly uses ex-used materials. In addition to low cost and production gain, "autocyclic" helps operators to prioritize more important tasks in the field.

Autocyclic is a simple double advantages technology. In addition to safety, well flowing cycle can be optimized and improved.