bluuebunny/crossref_metadata_2025 huggingface dataset:
Cutting Edge Completion Design for KNUUD: Pioneering HPHT Field Development in Malaysia
Authors: Bakar Mohd Farris , Miguel Rosato , Fadzliana Azmi , Sofian Anas M.
Published: October 2017

KNUUD was the first High Pressure and High Temperature (HPHT) field development well embarked by PETRONAS and first in Malaysia. Learning from experience of HPHT operators in the North Sea,a detailed focus on life cycle well integrity aspect has been thoroughly emphasized throughout the well delivery phase. Initial requirement for heavy brine (16.5 ppg), which led to heavy wall production casing and high probability of tubing leak where the worst case scenarios studied in deep detail.

An extreme underbalance completion philosophy was implemented for the first time in PETRONAS. Complex processes of identifying cost effective solutions for HPHT safety critical equipment, covering the initial scoping, completing, perforating and well testing, sourcing, preparation, quality assurance and installation was systematically followed. An in-depth investigation and philosophy of managing annulus pressure build-up were also performed as part of the lifecycle integrity assurance process.

Various validation works were successfully carried out to assure the identified solutions such as V1validation (API 14L/ISO 16070) for Flow Control Equipment (4.75" Tubing Hanger Plugand 4.313", 4.188" & 4.000" Top No Go Landing Nipple's Plug), ISO 13679 CAL-IV teston completion tubing connection, API validation (API RP 19B Section IV Perforation Testing) for 2-7/8" HMX charges with maximum 6,000 psi underbalanced approach.

The well was successfully installed while recording the following significant implementation milestones for operations in Malaysia; Underbalance completion approach with freshwater instead of heavy brine (6,000 psi UB).Implementation of Vam 21 connection for 5 ½" production tubing according to ISO 13679, Connection Application Level: IV (CAL-IV).Implementation of V1 rated 15,000 psi Flow Control Equipment according to API 14L/ ISO 16070.Implementation of 15,000 psi Coiled Tubing Conveyed Perforation with deployment system& wireless depth correlation system.Implementation of annulus pressure builds up (APB) passive management with nitrogen cushion.

The comprehensive thought process and extensive efforts put in the planning stage have opened doors for significant value creation for the well delivery process. Early engagement with service providers and unique contracting approach have enabled sufficient due diligence for competitive technical solutions as well as to bring in necessary expertise to the region.

The well was successfully delivered to meet all of its objectives, producing from layers close to 16,000ft beneath the seabed. The complex process, obstacles and experiences in overcoming the challenges have indeed pioneered a confident path for future application of its kind within Malaysia and Asia Pacific region.
Imaging of Oil/Water Migration in Tightsand with Nuclear Magnetic Resonance and Microscope during Dynamic Surfactant Imbibition
Authors: Sun Yongpeng , Dai Caili , Fang Yanchao , Sun Xin , You Qing , Wu Yining , Zhao Mingwei , Zhao Guang
Published: October 2017

Tightoil poses huge reservoir in many countries. Due to the poor reservoir properties, such as nanometer to micrometer pores, low permeability, energy deficiency, the oil recovery in tightoil reservoir is very low, even with horizontal drilling and hydraulic fracturing. The small pores are featuring large capillary pressure thus spontaneous imbibition. Surfactant would accelerate this process. However, due to the small amount of oil in core, the accurate recording of oil recovery is challenging, especially during dynamic imbibition within fracture matrix system. Nuclear Magnetic Resonance (NMR) T2 spectra was used to characterized the migration of oil and water in pores and throats during dynamic imbibition. Various phenomenons are revealed and proved by T2 spectra figure, such as: water imbibed into small pores, oil expelled from large pores, and oil film formed on fracture face. The oil recovery during dynamic imbibition was examined online during experiment from the peak area generated by T2 spectra. Before and after the dynamic imbibition, Magnetic Resonance Imaging (MRI) was used to compare the saturation and distribution of oil in the core sample. When the oil drop migrates out of the pores, it will emerge from the surface of rock sample. Its shape on top, lateral, and bottom of the sample was observed with a long distance microscope. Their growth in width and height was compared carefully. The growth rate was categorized into different stages, and quantitatively compared.
Geomechanical Study at An Onshore Central Sumatra Field: The Investigation of Casing Restriction and Deformation in Shallow Sand Formation
Authors: Tjengdrawira Marius Agustuhong , Khaksar Abbas , Ong See Hong , Sjari'at Raihan Intan , Suhadi Annur
Published: October 2017

Casing restriction was encountered during workovers in 10 wells in a field onshore Central Sumatra, Indonesia. The field is operated by BOB PT Bumi Siak Pusako – Pertamina Hulu. The problem was encountered in a shallow thin sand in the depleted mature field.

A geomechanical study was conducted to determine whether the casing restriction/deformation was from excessive loading, which may have been caused by reservoir deformation and/or shearing because of fault slippages. Geomechanical factors that can contribute to casing loading and shearing include sand failure leading to cavity formation and the loss of casing support in the production interval, reservoir deformation/compaction, faulting from pore pressure changes (depletion or injection) and the corresponding stress changes.

A field-specific geomechanical model was constructed using data acquired in four offset wells drilled in the field to quantify the stresses on the reservoir rock and the existing fault(s) under depletion and subsequent water injection. The model was used in failure analyses to determine whether the stresses were sufficient to cause rock failures and fault slippage that could potentially have deformed the casings.

The study highlights the value of geomechanics as a tool in the petroleum industry for solving production issues in mature fields. Understanding the risk of rock failure because of pore pressure and stress changes enables optimization of well placement, completion design, production parameters and reservoir management to maximize recovery of mature fields.
Design of Experimental Test Method to Investigate the Effect of OBM Contamination on PVT Samples from Gas Condensate Reservoirs
Authors: Bon J. , Bon P. J. , Ortega A. J. , Nalepa W. , Koo R.
Published: October 2017

PVT samples captured by openhole formation testers in wells drilled with Oil Based Mud (OBM) will often suffer some degree of measurable contamination1-5. The contamination is even further pronounced for gas condensate reservoir fluid systems. Often many years will pass before production or the opportunity to re-sample the reservoir fluid and these contaminated samples are all there is to work with until that time. Improved understanding of the effect that OBM will have on these fluids will lead to improved characterization of the native reservoir fluid.

The primary objective of this work was to design a new experimental laboratory method to contaminate a clean reservoir fluid PVT sample with OBM and capture the live single-phase fluid again under dynamic conditions.

This experimental set-up will enable a laboratory to prepare samples representing PVT samples captured by Wireline Formation Testers (WFT) from an OBM drilled well, as well as the clean reservoir fluid to work with for comparison. It is envisaged that such an experimental setup will be able to be used to generate data to then study the effect of OBM contamination of PVT samples and ultimately improve the ability to correct PVT data on contaminated samples to obtain representative PVT properties.

In order to test the experimental test method, base oil from an OBM was used to contaminate a gas condensate PVT sample with Condensate Gas Ratio (CGR) of 25 stb/MMscf. The data obtained from results from both contaminated and uncontaminated sub-samples were then used to investigate the effect of OBM on PVT properties.

Sufficient sample was obtained in order to measure dew point, Z-factor, CGR and composition of the resulting contaminated samples to compare to the same properties from the original uncontaminated reservoir fluid sample.

In this paper we present the following: A new experimental set-up was designed to create contaminated PVT samples from a clean sample under dynamic conditions – flowing within a porous media at reservoir conditions.With the experimental set-up we were able to obtain samples and data for comparison of a clean and OBM contaminated sampleResults indicate that under the right conditions, a condensing-vaporising partial miscibility dynamic is established between the gas condensate reservoir fluid and base oil.
Unique & Practical Approach in Selection and Classification of Hydrocyclone Desander Technology: Utilizing a Decade of Experience
Authors: Gupta A. , Kamat D. , Shahrum Z. , Firmansyah A. , Salleh N. I. , Tan B. C. , Madon B.
Published: October 2017

With the advent of advancement in hydrocyclones in oil industry, there has been various types of hydrocyclone based desanding system developed each with its own pros and cons. Main challenges being the handling of multiphase fluid resulting in four phases of feed and challenges in designing. Operators had been facing various challenges in sand management since a decade which has resulted in installation of various hydrocyclone based desanders. Many of the hydrocyclone based desanders did not perform as per expectation and mixed results were observed. With more sand handling issues expected in future, a study was conducted to ascertain lessons learnt and challenges in past installations and way forward for future.

A focussed team which includes production technologists and process specialists was established. The team compiled the installation histories of earlier installations and challenges. These included design, operational and logistic details for any installation. Approximately 15 different desander technologies currently prevalent in market and within the region were evaluated to understand the mechanism and variety of each type.

The cyclone system was categorized into fixed, changeable with insert and dynamic cyclonic desander for ease of evaluation. The learnings from the earlier installations indicated significance of category which needs to be considered for an installation. Parameters like pressure drop across the cyclone, inlet pressure at the cyclone system, particle size separation, gas volume fraction at the feed volume of sand being produced, sand handling capability of the facility etc. turned out as significant contributors for selection of desanders. Operator's conditions of high gas volumes, relatively finer particles being produced and low pressure environment turned out to be biggest technical challenges in selection of a proper desander. Other challenges included importance of a multi-disciplinary team, contracting strategy and type of desander to be deployed. It was apparent from the study that any future installation would require more systematic approach rather than "pick up from shelf" approach on the desanders.

A unique selection flowchart was established as a guideline for selection of hydrocyclone desanders on the basis of major parameters to decide not only on the type of desander required but also the location of desander in a facility. The new by defined category eased out this entire process. To avoid any failure for future selection and installation, a well-defined contracting strategy was established to encompass various types of desanders easing the selection process and utilizing the study results. This entire effort resulted in huge potential value creation and promised a significant saving in man hours.
Solids Production Prediction and Management in a High Porosity Carbonate Reservoir - A Case Study from Offshore Vietnam
Authors: Asadi M. S. , Khaksar A. , Nguyen H. Q. , Manapov T. F.
Published: October 2017

Carbonate reservoirs hold 50 to 60% of the world's conventional hydrocarbons and are therefore of major economic significance. Solids production from poorly consolidated carbonate reservoir rocks is a common factor in many wells during production stages and especially in the later life of a reservoir under depletion conditions. While there are several well-estblished technuues to predict sand production in sandstone reservoirs, there are not many field-proven case studies on the applicability of these techniques for solids production assessment in carbonate rocks. In this study, we present a case study on the application of a widely-used sanding evaluation technique in a carbonate gas reservoir, offshore Vietnam.

We show production, core and well data from several production and appraisal wells in three nearby gas fields to investigate the cause of well productivity reduction in one well through a systematic geomechanical assessment of solids production. The findings are used to optimize gas production in existing wells, determine maximum solids-free drawdown for a planned infill well, and completion decisions for two new development wells to be drilled and completed in 2018 in a field with no production to date.

Rock mechanics tests conducted on several carbonate samples confirmed the low strength and high heterogeneity nature of the reservoir carbonates. Core-log calibration of rock mechanics paramters revealed reasonably strong correlations between rock strength and porosity logs which were used to generate continuous log-derrived rock strength profiles. Applicability of a well-established poro-elastic sanding predction model for carbonate reservoirs was investigated by a logical solids production analysis in a cased and perforated explorationwell and two open hole production wells. Production, well testsand fluid sampling data were used to calibrate and verify the solids production model.

Analysis showed no risks of solids production for the weakest reservoirs at initial and current reservoir pressures with the current applied drawdowns, and the drawdown can indeed increase in exsiting wells by another ~200 psi without the risk of solids production. The results however indicated that as the reservoir pressure reduces the solids-free drawdowndecreases rapidly and will approache zero when the reservoir pressure dropsby another600-800 psi. Therefore, solids control measures are essential to prevent solids production at later life of the field.

The results of the study and historical knowledge of the field reservoir and production were used for completion design of two vertical infill wells with the aim of increasing production from one of the major gas-producing blocks for Vietnam's domestic gas supply. The infill vertical wells will be completed open hole with external gravel pack and screen as the solids control measures.
BD Field Development: First Kujung Horizontalnear HPHT - Critical Sour Wells Offshore Indonesia
Authors: Lian J. , Tian Y. , Yang Z. , Yustendi K. , Rizkiani D. , Nurdin S. , Mcken D. R. , Etuhoko M. O. , Jiang K. , Diemert A. P. , Fadil M. , Utomo P. P. , Mahry A. , Yudento S. D.
Published: October 2017

The Company had successfully drilled 4 challenging BD Development Wells (1 vertical and 3 horizontal). BD Field reservoir is aKujung 1 limestone reef, considered near HPHT and critical sour with 8,100 psi Bottom Hole Pressure (BHP), 300℉ Bottom Hole Temperature (BHT), 5.5% CO2 and 5,000 ppm H2S. This paper highlights the design phase and well deliverability covering pressure window, casing design, material selection, wellhead and Christmas tree, directional drilling planning, drilling fluid, cementing consideration, well completion, annulus pressure management, and project challenges.

The data from two offset wells with surface location radius fewer than 2,000 ft from BD Platform were used as reference for lessons learnt and design for the casing seat selection. Based on the Wellbore Stability Study and the offset wells data, there exists a narrow mud weight window between pore pressure and fracture pressure. The directional plan was developed to have sufficient well separation in the upper hole section and enable fewer dog leg severity requirement to drill in the down hole section. Material selection for casing was designed based on the expected life of the well and reservoir properties in accordance to the requirements of NACE. Drill-in fluid system (Potassium Formate and Manganese Tetraoxide) with mud weight of 14.9 ppg was used to drill the limestone reservoir section providing minimal damage to the reservoir. Production casing cement was tested and analyzed in the laboratory for 60days in the HPHT chamber simulating reservoir properties. Open Hole Monobore Completion approach was selected to complete the well. In order not to compromise well integrity, annulus pressure management technique was fully implemented during drilling, completion, and well clean up phases.

The wells were successfully executed despite several challenges which required unique mitigations to manage. During well clean ups, all wells were able to exceed the Absolute Open Flow (AOF) expectations.
An Analytical Model for Multilayer Well Production Evaluation to Overcome Cross-Flow Problem
Authors: Hakiki Farizal , Wibowo Aris T. , Rahmawati Silvya D. , Yasutra Amega , Sukarno Pudjo
Published: October 2017

One of the major concerns in a multi-layer system is that interlayer cross-flow may occur if reservoir fluids are produced from commingled layers that have unequal initial pressures. Reservoir would commonly have bigger average reservoir pressure (pore fluid pressure) as it goes deeper. The phenomenon is, however, not followed by the reservoir productivity or injectivity. The existence of reservoir with quite low average-pressure and high injectivity would tend experiencing the cross-flow problem. It is a phenomenon of fluid from bottom layer flowing into upper layer. It would strict upper-layer fluid to flow into wellbore. It is as if there is an injection treatment from bottom layer. The study deploys productivity index an approach parameter taking into account of cross-flow problem instead of injectivity index since it is a production well. The analytical study is to model the reservoir multilayer by addressing to avoid cross-flow problem. The analytical model employed hypothetical and real field data to test it. The scope of this study are: (a) Develop mathematical-based solution to determine the production rate from each layer; (b) Assess different scenarios to optimize production rate, those are: pump setting depth and performance of in-situ choke (ISC) installation. The ISC is acting as an inflow control device (ICD) alike that help to reduce cross-flow occurrence. This study employed macro program to write the code and develop the interface. Fast iterative procedure happens on solving the analytical model. Comparison results recognized that the mathematical-based solution shows a good agreement with the commercial software derived results.
Novel Application of Capacitance-Resistance Model for Reservoir Characterisation and Zonal, Intelligent Well Control
Authors: Prakasa Bona , Shi Xiang , Muradov Khafiz , Davies David
Published: October 2017

Numerical reservoir simulation is a valuable, computationally expensive, tool for the design, evaluation and operation of hydrocarbon fields. Such reservoir models are complex, time consuming to build, yet uncertain; being based on limited information. The use of alternative models based on the field's production history data to reliably quantify inter-well connectivity and support well control decisions is preferred. This paper extends their application to a field with Intelligent production Wells (IWs) equipped with downhole monitoring and flow control. A field with IWs is a natural candidate for closed-loop, reservoir model update and field optimisation.

The Capacitance-Resistance Model (CRM), one type of data-driven models, has proved to be effective for making well production optimisation decisions in a single-layer, mature, water flooded reservoirs. This study extends the application of CRMs to a multiple-layer, heterogeneous reservoir being developed by IWs. The optimisation strategy was further extended to include both injection and production control at the level of an IW zone. The resulting, CRM-based, proactive optimisation strategy using zonal production/injection history data proved to be capable of delaying water breakthrough and increasing recovery.

This paper describes and compares the reliability of three CRMs in synthetic, single- and multi-layer, reservoir models. The optimum CRM complexity is a function of the reservoir's geological complexity and the complexity of the chosen optimisation strategy. The CRM calculated inter-well, layer connectivity results can be used to suggest changes to the operation of one or more IW zone's injection or production rate. The CRM can be updated once sufficient further injection and production data has accumulated.

A comprehensive CRM -based, closed-loop workflow of data gathering, history matching and optimisation has thus been described. The workflow, programmed as a spreadsheet, is a complementary tool to numerical reservoir simulation, providing insights into both reservoir characterization and production control in intelligent and conventional field developments.
Development of Well Integrity Management Tool in Mahakam Block
Authors: Priwanza H.. , Saputra R.. , Manalu D.. , Muryanto B.. , Nuryanto Y.. , Dirgantoro A.. , Maharanoe M.. , Sari K.. , Sayogyo B.. , Hutahean R.. , Dewanta D.. , Wibowo A.. , Limawan V.. , Darma R..
Published: October 2017

Total E&P Indonesie (TEPI) has been the operator of Mahakam Block in East Kalimantan since 1968. In a mature field with aging wells, well integrity becomes a vital aspect to ensure all wells are operated within the design envelope during well's life cycle. This paper discusses development of well integrity management tool in the Mahakam Block to manage more than 2000 wells with various integrity threats.

The well integrity management tool developed in TEPI is called SWIM (Smart Well Integrity Module). SWIM acts as a systematic follow-up tools and single database for concerned entities within the Company. On the well integrity management tool logic, NORSOK D-010 barrier concept is applied for a universal approach to all types of well in production regardless of the well completion date as a means to assess the integrity.

Three main components will be assessed to determine integrity status of the well, which are: Two barrier envelopes (External and Internal), and Annulus Pressures as its behavior indicates well integrity issue. The software processing logic will then generate the Well Integrity status depends on the status of barrier component or annulus pressure condition. The general well integrity conditions are then represented by assigning color codes. Four color codes, Green/Yellow/Orange/Red, are utilized for visualization purpose of criticality ranking. Green and Yellow are indicating acceptable well integrity status, meanwhile Orange and Red are highlighting one or several integrity issues on the well and prioritization to perform a restoration job.

The SWIM as single portal and integrated software provided with accurate data inputis beneficial for Company in terms of criticality rankings and data reliability for monitoring thousands of well integrity condition, allowing proper assessment, fast-follow up, and data gathering to propose suitable intervention or repair if required.
First Fiber-Enabled CT with Reservoir Saturation Tool in Asia to Unlock Behind-Casing Opportunity in Offshore Myanmar
Authors: Mohallem R.. , Jenie J.. , Hami Z.. , Nazri A. Mohamad , Zaman N. Kamarul , Salleh K.. , Htun Y. Min
Published: October 2017

An infill drilling campaign in offshore Myanmar was facing challenges to accommodate well intervention activity in order to achieve additional production targets; therefore, there was a need to search for an alternative, cost-effective solution in the current environment. A well with potential behind-casing opportunity was identified, and an innovative solution was proposed using coiled tubing (CT) fiber-optics real-time telemetry combined with the latest high-power battery cartridge technology to convey a tool capable to identify the reservoir saturation and conclusively detect the bypassed zones.

As a result of rig-up constraints, a standalone wireline unit could not be used to deploy the reservoir saturation tool on the selected well. The innovative solution was to convey the reservoir saturation tool using CT fiber-optics real-time telemetry along with the latest-technology high-power battery cartridge system, allowing real-time logging with CT, including additional safety precautions and radiation hazard controls while using the pulsed neutron generator device.

The intervention was performed concurrently with drilling operations on an adjacent well. A major effort was put in place to plan and execute this operation, especially because open well deployment was needed to address the rig-up height issue while doing the job below the rig floor; this was in addition to the extensive HSE risk mitigation for using the radioactive pulsed neutron generator device. The well was killed successfully, and the reservoir saturation tool was conveyed with CT to the target zone where two logging passes were made. Data were then sent for interpretation, and the CT was pulled back to surface after confirmation of data quality. As a result, the operator obtained conclusive data, and the decision was made to shut off the existing perforated zones and perforate the identified BCO. The simultaneous intervention and drilling operations, reduced footprint, and the additional production from this well saved the operator up to USD 2 million. With the integration of CT and wireline technologies and the introduction of a novel battery system for high-consumption logging tools such as the reservoir saturation tool, the operator efficiently and cost-effectively acquired data without nonproductive time (NPT) or compromising safety during operations.

An innovative and first-time operation in the entire region (Asia), the use of CT fiber-optics real-time telemetry combined with the latest high-power battery cartridge technology to deploy the reservoir saturation tool overcame operational challenges and enabled successful identification of the bypassed zone. The combination of these technologies can benefit other regions and other similar operations.
Breaking Boundaries in Portfolio Management
Authors: Gama B. , Macmillan F. , Roithinger J. , Gieles T. R. , Bulgariu R.
Published: October 2017

The challenges currently faced by the E&P industry are unparalleled. Subdued hydrocarbon prices and an increased pressure to minimise cost structures provides a convincing reason for managers to implement effective portfolio management technologies. The objective of this paper is to provide a practical portfolio management framework which balances the often conflicting requirements of managing short term financial stresses and long term strategic growth.
Expanding Innovative Approach of Sand Production Well Remediation - Case Study of First Downhole Ceramic Sand Screens for a Gas Well in Malaysia
Authors: Musa M Nizar , Ismail W Rokiah , Roh Cheol Hwan , Zulkifli Shahrul Anwar , Hui Nicholas Foo , Jackson R.. , Gundemoni B.. , Barth P..
Published: October 2017

The current state of oil and gas economics has emphasized focus in managing and optimizing production from mature fields. It is estimated that approximately 70% of the world's oil and gas production are contributed by mature fields. Sand production is common as pressure declines and water breakthrough takes place. Clastic reservoirs with unconsolidated formation sand with moderate and high permeability are prone to produce sand under these conditions. In gas producing environments, conventional sand control can place demands for continued expensive remediation investment through the wells producing life as high gas velocity increases the chances of erosion and failure of downhole equipment. Gas reservoirs have always been an integral part Malaysia's oil and gas business. As the well the portfolio expands to cater for the regional energy demand, focus on fit for purpose sand control in gas wells is crucial in ensuring continuous production delivery to customers. As a current practice, sand production has been handled by standalone metal screens or combined with gravel packing. One of the cheaper options available in the market is the ceramic sand screen that allows for rigless installation while providing durable material which is resistant to erosion caused by high gas velocity for a continuous production as the ceramic material is 10 times harder than steel (Jackson et al., 2015) and it is more resistant to corrosion in comparison to steel (Wheeler et al., 2014).

This paper will focus on the revival strategy of a gas well with a currently damaged screen due to erosion. As this is the first through tubing ceramic sand screen deployment in a gas well in Malaysia, a feasibility process was put place to ensure safe operation and deployment success. Depending on the current well completion profiles, the assessment includes selection of sand screen specification, actual installation sequence, methodology in ensuring safe and successful deployment of ceramic sand screen downhole are focused. The study and assessment has provided future reference for superior downhole sand control options in gas well applications.
Hydraulic Fracture Design and Well Spacing Optimization for Gas-Condensate Reservoirs
Authors: Abdul-Latif Benson Lamidi , Hikmahtiar Syouma
Published: October 2017

In state-of-the-art production data analysis and computational methodologies applied to multiphase lease condensate flow, condensate-banking effect is usually neglected to enable easier analytic treatment. However, neglecting the amplified role of condensate banking in multiphase flow in unconventional formations may generate misleading analytical results and calculations during hydraulic fracture design and optimization.

This work proposes a semi-analytical model eminently applicable to unconventional reservoirs to incorporate the effect of condensate banking in hydraulic fracture design and well spacing. Analytical models for Darcy flow above and below the dew point pressures were considered whilst estimating the optimum fracture design in gas condensate reservoirs using Schechter's approach and incorporating the effects of the condensate blockage radius.

The validity of the series of proposed semi-analytical solutions that capture condensate-banking effect in unconventional reserves is verified by discussing a number of cases and comparison against full-scale numerical simulation data.
Integrated Reservoir Analysis and Geomodeling on Shallow Zone of Handil Field, a Key to Identify Un-Swept Area for Future Development of Mature Oil Field
Authors: Benidiktus G. Massuka , Andar Trianto , Sinto Yudho , Bayu Setyo Handoko , Iswahyuni F. Hayati
Published: October 2017

This paper describes a new methodology to identify the un-swept areas for future infill well location in Handil shallow zone. This methodology has been proven by more recent Handil shallow oil (HSO) wells results.

Handil shallow oil zone plays an important role as it contributes to 60% of today’s Handil oil production. Shallow zone was initially produced in 1977, reached its peak of production 37,000 BOPD, in 1981 and continued to decline until the lowest level of 2,500 BOPD in 2005. The re-development project was started in 2005 to revive the contribution from shallow zone. The project has delivered 42 HSO wells to date with cumulative production of 26 MMstb and current average production of 10,000 BOPD.

The reservoirs are fluvio-deltaic sand with strong aquifer support which maintains the reservoir pressure in hydrostatic level. The compartmentalization of the reservoir by faults and facies heterogeneity, combined with HSO wells production impact, resulted in variation of water movement within the same stratigraphic layer in one reservoir segment. The tilting oil water contact (OWC) was observed and it reveals the opportunity to find un-swept areas in mature field. This phenomenon was observed in HSO wells drilled since 2005 to 2015. The behavior of fluid contact was analyzed from log, confirmed by formation tester and from production logging tool (PLT) in existing production wells.

A new methodology was introduced to identify the un-swept areas for future infill well location. Detail reservoir correlations within individual deltaic cycle of more than 400 wells, integrated with reservoir dynamic synthesis, were performed to define the reservoir architecture and to characterize the water movement (actual and future OWC). The 3D reservoir model was built according to these syntheses and an individual dynamic region with similar OWC movement within the same stratigraphic layer was created to honor the compartmentalization of reservoirs. This has led to the identification of un-swept areas in top structure and also in the flank areas with less production activity.

The methodology has become a game changer in finding remaining oil. More infill well locations are identified by using this approach for future Handil field development.
Pressure Transient Analysis for Cold Water Injection into a Reservoir with a Coupled Analytic Wellbore Model
Authors: O'Reilly D. I. , Haghighi M. , Flett M. A. , Sayyafzadeh M.
Published: October 2017

In this short technical note we lay out an analytical framework to assess the impact of transient temperature changes in the wellbore on pressure transient response of cold water injection wells. We focus attention on the falloff period of an injector following injection. Historically, these pressure data have been used to calculate reservoir properties concerning flood efficiency and completion properties, e.g.: formation permeability-thickness, mechanical skin and fluid bank mobilities. One key question addressed in this paper is whether the effects of thermal heating of wellbore fluids during a falloff survey can mask the pressure signature of a two-zone composite reservoir. The pressure deflections required to detect mobility changes may be relatively small compared to pressure changes induced by temperature effects in the well. The framework proposed in this paper allows for the numerical evaluation of the contribution of each.

Previously, researchers have studied multiple bank transient injection problems extensively for the case of reservoir flow and pressure drop, even for non-isothermal problems. The effect of temperature changes in the wellbore and overburden are seldom discussed, however. It is demonstrated in this paper that these effects can, in some cases, be substantial and it is worthwhile to incorporate them into an interpretation model.

The results of this paper are useful for planning and designing a pressure falloff survey to minimise the adverse effect that heating of wellbore fluid by overburden rock may have on the pressure transient signature. The theory can also be used to analyse existing data affected by the phenomenon.
First Application of Residue-Free Fluid System for High Temperature Fracturing Treatment in Saudi Arabian Carbonate Formations
Authors: Rahim Zillur , Al-Kanaan Adnan , Zeghouani Mohamed , Khalifa Mohamed , Krich Driss
Published: October 2017

Acid Fracturing technique is an alternative to propped fracturing in acid soluble formations. Factors controlling the effectiveness of acid fracturing are the etched fracture penetration and conductivity. Large volumes of acid and the dissolution of large volumes from thefracture faces with excessive acid leak off result in negative net fracturing pressures and less optimized etched fracture length. This paper describes the first application in Middle East area of a nitrogen assisted residue-free fracturing fluid system to successfully stimulate a carbonate formation.
Bio-Inspired Superhydrophobic Coatings with High Performance for Subsea Petroleum Equipment
Authors: Jin Xu , Chen Yu , Li Jianming , Wang Xiaoqi , Bi Lina , Bai Jie , Wu Juntao
Published: October 2017

Bio-inspired superhydrophobic Polyphenylene sulfide/Polytetrafluoro-ethylene (PPS/PTFE) coatings were prepared by a simple curing process. The surface morphology characterization by SEM shows that these superhydrophobic coatings have the similar macro-nano-structures to that of lotus leaf. Effect of the content of PTFE as well as the curing condition on the water contact angle of the superhydrophobic coating surface was then systematically studied. A series of tests show that the superhydrophobic coatings exhibit high cohesional strength, excellent impact resistance and high thermal stability. Moreover, we studied the stability of chemical resistance of the as-prepared superhydrophobic PPS/PTFE coatings, and the electrochemical impedance values kept on a high level even after 8 days. The superhydrophobic PPS/PTFE coatings with high performance have potential applications in subsea petroleum equipment fields.
Study and Application of Snubbing Technology for Low Pressure Gas Well
Authors: Han Weiye , Li Tao , Wang Dabiao , Ming Eryang , Huang Shouzhi
Published: October 2017

With the further development of natural gas, the quantity of gas well has been increasing year by yearin China, the demands for well completion and workover are growing. At present, more than 70% of gas wells are low yield and low pressurein China, in order to protect the reservoir and make the production stably, it's an urgent need to use snubbing technology for low pressure gas well.

Snubbing technology faces several challenges for low pressure gas well, such as high risk, complex downhole conditions, high cost, low operation efficiency, etc. High efficiency, low cost and low risk are crucial targets for gas well snubbing. To achieve this target, we developed a set of snubbing wellhead for low pressure gas well which operation pressure is less than 14MPa. Some key technologies are formed, such as airtight makeup and breakout device, gas sealing system, rotating slips etc. The unit can realize pipe tripping and rotating operation with high efficiency and low risk in low pressure gas well, it's composed of lifting system, gas sealing system, working BOP stacks, airtight makeup and breakout device, security BOP stacks. The main working principle is adopted liquid to seal gas, the gas sealing system is composed of two sets of annular preventers, and a length of liquid which has 3-4MPa pressure is sealed between them. When it comes to begin snubbing operation, the gas sealing system can realize effective sealing within the wellbore pressure and also achieve the purpose of tubing lubrication, the safety and reliability can be well guaranteed when it works with BOP stacks. The airtight makeup and breakout device is equipped between the working BOP stacks and security BOP stacks, cooperate with the rotating slips, tubing joints can be screwed on and off at the bottom of the snubbing wellhead when it meets special snubbing work conditions, such as no tubing plug or tubing leakage.

The pilot test of this technology is carried out in Jilin oilfield, operation cost is reduced about 50%, and it makes the production development more effectively and economically.

The annual demands of snubbing operation for low pressure gas wellare probably more than2000 wells each year in China, This technology has the advantages of high efficiency, low risk and low cost, the application prospectis broad.
History Match to Support Interpretation of Surfactant Flooding Pilot Test in Tanjung Field
Authors: Aslam B. M. , Ulitha D. , Swadesi B. , Fauzi I. , Marhaendrajana T. , Purba F. I. , Wardhana A. I. , Buhari A. , Hakim R. , Hasibuan R.
Published: October 2017

Tanjung Field is a brown field which pressure has already depleted and been supported by waterflooding for over a decade. To improve production, surfactant injection, is being studied to be employed in the field. The main objective of this study is to identify parameters that affect oil production increase. History match of the pilot test was carried out to improve the reliability of the reservoir model, hence improving the prediction result of surfactant injection forecast.

History match of the pilot test has been carried out using CMG STARS commercial simulator by considering mechanism inferred from laboratory evaluation such as wettability alteration, surfactant retention, interfacial tension reduction and improvement of mobility control due to lower oil-surfactant emulsion viscosity. These parameters are initially perceived from laboratory result, upscaling and adjustment is applied to field model to further on do sensitivity study. Sensitivity analysis of every parameter is provided to better understand the effect of each mechanism that contributes to the oil incremental result.

Stratigraphically, Tanjung Structure has 7 productive zones: Zone A, B, C, D, E, F and P. Reservoir Zone A has total estimated reserve of 193,732 MMSTB, with recovery factor of 16.3%. The zone consists of conglomerate sandstones with porosity of 21% and permeability ranging from 10 to 100 mD. The field produces light oil within 40 °API, 30% wax content and 1.14 cP of viscosity. T-119 is the well chosen to be injected due to its structural position that ease flow by gravity force to producer wells.

Forecast simulation based on coreflood result has been conducted for pilot test. However, the result was very pessimistic in predicting incremental oil gain and breakthrough time after compared to pilot result. An attempt to history match the surfactant flood pilot is presented by considering phenomena that is not included in the forecast based on additional lab and field data.
ICDs for Uncertainty and Heterogeneity Mitigation: Evaluation of Best Practice Design Strategies for Inflow Control Devices
Authors: Lim Michelle
Published: October 2017

Inflow Control Devices (ICDs) are an advanced well completion device used primarily in horizontal wells to enable more efficient reservoir flow performance and to mitigate common production issues by applying an additional pressure drop to choke high productivity zones. This study aims to identify design philosophies that provide for the most robust ICD design, and to determine if ICDs can be implemented for subsurface uncertainty mitigation. As there is no ability to adjust ICD settings once installed without major recompletion, a completion design that is robust to reservoir uncertainty at and away from the wellbore is critical. While ICD design follows a basic set of guidelines, several different approaches exist for each step within this workflow. A major design aspect relates to the design of target inflow profiles (equal inflow or U-shaped inflow). The U-shaped target inflow profile hypothesis was initially proposed for homogenous wells. This study proposes a modification to the existing design philosophy to cater to heterogeneous reservoirs. There is evidence supporting the use of the less conventional U-shaped target inflow profile in ICD design over the more commonly used equal inflow profile method. Sensitivity and robustness under reservoir uncertainty and heterogeneity for each ICD design methodology was assessed using 3-dimensional numerical reservoir simulation of layered and non-layered heterogeneous block models, followed by extensive uncertainty analysis. It was found that ICD completions may be unsuitable as a method for uncertainty mitigation and use of ICDs for this reason must be thoroughly investigated using full uncertainty analysis in dynamic simulation.
Screening of Chemicals for Low Cost Heavy Oil Recovery through Microemulsion Stability Tests
Authors: Lee Jungin , Babadagli Tayfun
Published: October 2017

This paper reports the results of laboratory scale screening of different chemicals for their microeumlsion generation capabilities to be eventually recommended for non-thermal heavy oil recovery (chemical flooding). The study was performed through visualization of microemulsions generated using vials and microscopic images. The impact of salinities of brine on the emulsification was studied thoroughly in order to identify the synergy between the selected chemicals and the heavy oil. An alcohol propoxy sulfate surfactant from the Alfoterra series, Alfoterra S23-7S-90, a nonionic surfactant HORA-W10, gave good emulsion formation results at low salinity conditions (2.5 wt. %, 3.8 wt. %). Polysorbate-type nonionic surfactant Tween 20 gave good emulsion formation at high salinity conditions (6.35 wt. %, 7.6 wt.%). Their emulsion formation performance with a crude heavy oil of viscosity 4,812cP and 11.74 °API helped create an initial correlation of performance with the composition of crude oil and synthetic brine samples of various salinities. Attempts were also made to stabilize oil-in-water emulsions formed with Alfoterra S23-7S-90, HORA-W10, Tween 20 using nanofluids (metal oxides), sodium carbonate, and an anionic polyacrylamide-based polymer (PolyFlood MAX-165). Emulsions were visualized under the Axiostar plus transmitted-light microscope and their stability was studied in order to screen the most optimal chemical (or chemical combinations) available for low cost heavy oil recovery.
Study on Remaining Oil Distribution Characteristics and Water Flooding Efficiency Improvement Technology after Polymer Flooding
Authors: Deli Jia , Xiaohong Tang , Fuchao Sun , Tie Chen , Yongzhi Zhu , Tong Guo
Published: October 2017

It has become a focus of concern for polymer flooded oilfields to further produce remaining oil after polymer flooding at the subsequent water flooding stage. Based on the basic theory of hydrodynamic flow field distribution, a method to produce remaining oil at the diversion lines was proposed in this paper, which controls the increase rate of water cut by developing rational fluid control and water flooding efficiency improvement measures according to remaining oil saturation and the polymer injection rate at the diversion lines. A pilot test block has been selected and it has entered into the subsequent water flooding stage after polymer flooding. The distribution of remaining oil in the pilot test block is more complicated than that before polymer flooding, and the water cut is as high as 97.9%. Both the fluid production rate and injection rate are high among similar blocks. Low efficiency or invalid circulation is very serious, and development problems are becoming worse. This paper systematically analyzed the distribution characteristics of remaining oil. At the subsequent water flooding stage, the distribution of remaining oil is more scattered, most of it distributes near the faults and at the fringes of blocks, and remaining oil at the top of thick layers is produced by shutting in some water injectors and executing fracturing. By identifying preferential flow pathways, stopping water injection, increasing or decreasing the injection rate, water injection is rationalized. After one year of application in the pilot test block, the fluid production has been reduced by 146,000t, and 722,900t of water has been conserved due to properly controlled water injection.