bluuebunny/crossref_metadata_2025 huggingface dataset:
Carbonate Geostopping to Refine Depth Uncertainty Using Borehole Seismic - A Case Study in Vietnam
Authors: Dac T. Nguyen , Sanders M. , Millot P. , Pham The P. , Tomohisa N. , Ryosuke K.
Published: October 2015

Drilling exploration wells always carry increased risk given the lack of offset wells. Once of the main uncertainties usually is the depth prognosis derived from surface seismic depth converted data. The accurate prediction of the depth of top carbonate while drilling carbonate reservoirs is important to avoid losses and well control problems. This can have a significant financial impact. This paper demonstrates the use of innovative look-ahead VSP technology in Vietnam to refine depth prediction of the top of carbonate ahead of the bit for accurate geo-stopping.

An offshore exploration well was being drilled in an area with drilling challenges. This was the first well in the field and lacked offset well velocity information, so there was a high degree of depth uncertainty to the top of the carbonate target from surface seismic interpretations, making drilling operations risky. An intermediate VSP was requested to look for reflections ahead of the intermediate TD using Schlumberger VSI1 tool. The VSP data was acquired in open and cased hole using an air gun cluster as the seismic source.

The drilling program required the casing to be set immediately above the top of the carbonate. By acquiring an intermediate VSP, the depth uncertainty was reduced and the target depth prediction was refined. This was achieved using the look-ahead VSP technique, from which the acoustic impedance and velocity ahead of the bit was estimated. This was combined with time-depth from the VSP data over the logged interval to help refine the predicted depth to the top of the carbonate. This was used to optimize the depth at which the casing was set. The depth uncertainty of the key formation top (top of carbonate reservoir) from the surface seismic interpretation was over 180m prior to drilling. The final prediction depth from the VSP interpretation is 7m shallower than the actual carbonate reservoir.

Guided by the inverted acoustic impedance log and velocity ahead of the bit from look-ahead VSP, a further 150m was safely drilled before setting the casing. The casing point was set successfully without penetrating the carbonate. The intermediate VSP results helped to decide drilling ahead in a safe manner with confidence, after setting the casing before penetrating the carbonate target.
Using High-Expansion Gauge Hangers to Collect Reservoir Performance Data for Improved Oil Recovery
Authors: Babin Jacques , Mlcak Matthew , Denmon Michael
Published: October 2015

This paper illustrates varying situations where the high-expansion hanger has proven to be a viable and valuable solution for reservoir analysis and optimization. Difficulties associated with acquiring accurate data using modern completion designs or new exploratory methods to optimize producing resources are also discussed in addition to solutions provided using the high-expansion hanger.

A new high-expansion gauge hanger is deployed on slickline or coiled tubing using a non-explosive setting tool, for completion and reservoir analysis during well testing. It can be positioned anywhere in the casing for through tubing and/or rigless operations. The high-expansion design provides a generous bypass flow area to increase accuracy of data recorded. A unique slip design enables reliable set in highly scaled or corroded pipe. Precise placement of downhole gauges on slickline reduces cost and improves accuracy of reservoir and production analysis for improved recovery and efficient well placement.

It is becoming more important to ensure the accuracy of reservoir performance data acquisition to maximize asset production and extend the life of the well. By using strategically placed sensors to accurately record critical information from multiple forms of testing and reservoir enhancement techniques, accurate data gained during testing phases ultimately leads to the best flow regime design and successful reservoir optimization. Modern completion design or reservoir stimulation techniques are effectively evaluated using data acquisition, aiding the development, refinement, and implementation of such techniques.

Anchoring sensors in wellbores without decreasing flow can be challenging when introducing new techniques or modifications; these flow-rate conditions can prevent the determination of production at the time and rate that could maximize production and revenue of the asset.

This paper examines difficulties associated with accurately acquiring downhole pressure and temperature data in complex well completions as a means to analyze reservoir properties and ultimately optimize the asset recovery. The high-expansion hanger provides a means for precise placement of downhole sensors in more challenging completions during well testing.

Being able to precisely position pressure gauges, sampling tools, or other memory-based logging mechanisms is of great value. By using the slow consistent power of the downhole electrical power generator tool as a setting tool, the gauge hanger provides increased reliability and creates a secure anchor point, regardless of scale buildup or location. It can be run on slickline, electric line, or coiled tubing (CT), providing multiple solutions.
3D Reservoir Mapping While Drilling
Authors: Viandante Mauro , Pontarelli Laura , Fernandes Fred , MacDonald Shona
Published: October 2015

A development campaign offshore Australia, with a total of 15 laterals in a challenging geological environment, has been successfully completed by Quadrant Energy. The main objectives were to geosteer and place the well path at an optimum standoff from the oil/water contact (OWC), while drilling at the interface of the gas/oil contact (GOC), when present, and at 1-1.5m TVD from the reservoir top when not.

The field is characterized by a series of transverse and longitudinal seismic and sub-seismic faults that bisect hydrocarbon-bearing sands which represent the greatest challenges in this development campaign. Evidence from exploration wells showed a thin column of heavy oil and a gas cap in the fault-bonded reservoir. A new multi-disciplinary methodology not only enabled Quadrant Energy to achieve its development objectives, but to develop a full subsurface picture of the Coniston field reservoir.

The use of the Reservoir Mapping-While-Drilling (RMWD) combined with Bed Boundary Mapping Tool (BBMT) and Multi-Function LWD services enabled the laterals to be placed at 1-2m TVD below the reservoir top or gas cap, when present, even in highly faulted sections. In addition to this precise placement the extreme depth of investigation of the RMWD service, in conjunction with the real-time multilayer inversion capability, constantly mapped the OWC at a distance up to 19m TVD below the wellbore. While drilling, different qualities of reservoir sands were identified and enabled the extensions of the wells’ TDs based on reservoir properties. The distance to boundary information, provided in real-time by the RMWD service, was used in real-time by the Quadrant Energy geology and geophysics team to update and validate the seismic model that provided increased confidence in the reservoir model and a more precise planning for future development wells.

This paper will illustrate the use of the latest LWD RMWD technology in a challenging geological environment. The paper will explore the close collaboration, teamwork, and integration necessary to drive innovation and demonstrate the outcomes of this successful campaign which have not only exceeded the development goals, but have also generated a full 3D view of the reservoir.
Conceptual Design for Offshore Pipeline Replacement in Mature Field by Flexible Pipe for Capex and Opex Optimization
Authors: Yananto H. , Girindra Y.
Published: October 2015

A study was initiated to evaluate the benefit of low capital cost and low maintenance cost technologies to rehabilitate pipelines in marginal fields to keep them running profitably and with an attractive return on investment (and with no sacrifice to safety and environmental risks). The challenge is to have a new technology with lower "Total" cost from design, procurement, installation, operation and maintenance during its life time.

In the appraise stage, several technology options were considered to select the best option to maintain the pipeline; API 17J Flexible Pipe with specific design for shallow water is the alternative option compared to traditional rigid carbon steel pipeline. The assessment process started with pipeline technology update, followed by technical compatibility/ acceptance, commercially available pipe sizing, installation total cost comparison, installation schedule, and operation-maintenance. The decision will be taken by decision tree using Expected Value Decision Analysis. The expected value of each option included CAPEX, OPEX, NPV, and all quantified aspects and risk.

From the assessment it was conluded that flexibles pipe has more advantages compare to rigid pipes in term of CAPEX, OPEX, resistance to corrosive fluid, ease of installation, ease of repair and maintenance, and ease of decommissioning. The capital cost for 6" F2-FP Flexible pipe is US$ 8.5 million with NPV US$ 37.4 million and IRR 31.7%. The expected monetary value of 6" flexible pipe in decision tree analysis is US$ 27.5 million, the highest among other two options. The flexible pipe is feasible to be applied in F2-FP pipeline replacement project.
Success Story: A New Development Concept Utilising New Advanced Technology in A Very Old Complex Mature Field
Authors: Ng K. F. , Afandi T. , Sa'adon D. , Ja'afar J. , Omar M. A. , Latiff N. A. , Santoso G. I. , Alang K. , Roberts I. D. , Murad N. , Permanasari D. , Kutty F.
Published: October 2015

T-Field, located offshore East Malaysia, is a matured oil field that beganits development in the 1970s. Conceptual geological model generally illustrated this field as retro-gradational turbidite setting. The major reserves are contained in the stage IVD sequence, which is of late Miocene in age. The gross oil-bearing interval is about 300 m thick, divided into three(3) groups of sands (U -Upper, M-Middle and L-Lower stage IVD). As the "low hanging fruits" exist but are limited within this 40 years old matured field, drilling along the reservoir bedding plane was introduced as the best way to optimise the oil recovery in this field, where maximum reservoir-wellbore contacts and lower drawdown are expected to be achieved.

It is commonly known that the turbidite channel has enormous geological complexity and therefore presents great challenges for successful horizontal well placement. The discontinuity of sand packages, highly anisotropic environment with the presence of thinly laminated sand and the lateral heterogeneities in horizontal zone are the biggest challenges in the implementation of this new drilling approach. Therefore, good well planning and right geosteering decision during drilling are crucial to achieve the well objectives. A reservoir mapping-while-drilling technology with capability to map the multiple sand layers in larger scale (up to 30m Depth of Investigation) was utilised to provide a clear picture of the reservoir structure during well landing and after entering the reservoir to stay inside the reservoir sweet spot for optimum production.

This paper captured the first job in South East Asia in developing horizontal well placement in turbidities environment. It elaborates the highlights, success story and lessons learnt in using the latest technology which was proven as the most advanced geosteering and reservoir-scale mapping tool. This technology has not only enabled the drilling of 600 m-MD oil column, doubled net-to-gross ratio of sand penetrated and doubled the oil production of target reservoir but it has also helped the asset team in proper reservoir characterization and redevelopment planning.
A Strengthening, Modification & Repair (SMR) Decisionmaking Toolkit for Structural Integrity Management (SIM) of Ageing Offshore Structures.
Authors: Nichols N. W. , Khan R. , Ng S. M. , Lee L. A.
Published: October 2015

The Strengthening, Modification & Repair (SMR) toolkit is currently integrated into PETRONAS Carigali Sdn Bhd (PCSB) Structural Integrity Compliance System (SICS) which is a web-based application for the Structural Integrity Management (SIM) of fixed offshore structures. The objective of the SMR toolkit is to allow a user (engineer/manager) to quickly and efficiently determine all available SMR options for both jacket and topsides. The toolkit aids in the selection of suitable SMR technologies for a range of applications based on several key information as entered by the user. The Toolkit provides a variety of SMR options from key case studies from global and local databases and provides the most appropriate solutions for the SMR on both jacket and topsides structures of fixed offshore structures. The toolkit also has the ability to make use of other resources such as availability of particular vessels in specific operating regions, financials, logistics, technical expertise and other decision-making criteria prior to the engagement of implementation of any costly SMR scheme. The SMR decision-making toolkit is ideal for practising structural integrity engineers in operations to perform high level feasibility studies in determining preferred SMR options. The database is continuously updated to provide new options on case studies, availability of other resources and expertise, including availability of vessel and technical resources including the pricing, to ensure operators have the best information at hand prior to making decisions on SMR.
R&D Technologies for Acid Gases Extraction from Natural Gases
Authors: Bagirov Lev A. , Imaev Salavat Z. , Borisov Vasily E.
Published: October 2015

This paper describes main processes used for removal of CO2 from natural gases and some results of under R&D technologies of acid gases extraction from natural gases, including the method of 3S-technology (SuperSonic Separation technology).

There are various methods of acid components extraction from the natural gas: adsorptive, adsorptive, membrane, cryogenic and their various combinations. All mentioned technologies are notable for necessity to use a large number of accessory equipment, including bulky one that leads to the high capital investment costs and great operational costs, and also to the costs for restoration of adsorbents/absorbents, clearing of membranes, etc. These circumstances make the existing technologies inapplicable in terms of cost efficiency.

At the same time, a significant progress was recently being made in the development of new low-temperature processes of extracting CO2 from natural gas. Low-temperature processes are specially promising in processing of gases with high CO2 content. Several low-temperature processes of CO2 removal are presently known: –Ryan Holmes method;–Controlled freeze zone method (CFZ);–Cryocell method (Cryocell);–Sprex method (Sprex);–Gasdynamic separation of gas mixtures (3S-separation).

All 5 above mentioned low-temperature processes of acid components extraction will be considered and analysed in this paper.

While the main focus is on the analysis of 3S-separation technology.

3S-separator is a low-temperature supersonic separator, based on natural gas cooling in a supersonic swirling flow. Supersonic flow is implemented using a convergent-divergent Laval nozzle. In this nozzle, rapid cooling of gas takes place due to the conversion of flow potential energy into kinetic energy.

This workcontains a detailed description of 3S-technology. Someexistential schematic diagrams of devises based on 3S-separation will be presented in this paper. The advantages and limitations of this technologyhave been investigated during the study.

Currently3S-separators have been successfully operatedat severalgas processing facilities. Experimental studiesof CO2 separation from naturalgaswere carried out onthe test unitwith the3S-separator, designed for 6000 nm3/hour gas flow. Duringtests it has been shownthat the technologymakes possible theseparation of CO2 inthe carbon dioxide crystallization zone. The performed tests demonstrated that it is possible to achieve less than 3% mol CO2 concentration in the inlet gas.
A Novel Approach To Predict Interaction Between Hydraulic Fracture and Natural Fracture Using Artificial Neural Networks
Authors: Chen P. , Rahman M. M.
Published: October 2015

Hydraulic fracturing is a common applied stimulation method to develop the tight gas resource which is widely distributed all over the world. A lot of field measurement and experimental observation have shown the hydraulic fracture (HF) complexity in the environment of tight sandstones. This complex fracture is strongly influenced by the natural fractures (NF) which are inherent in the tight gas formation. It was documented that, as a result of interaction, the hydraulic fracture will cross, dilate or slip into the natural fracture. Though some researches have been done, the interaction mechanism is still not fully understood. The lack of knowledge in this topic calls for further research in it.

With this study, two neural networks methods are used to establish models to predict the interaction pattern between HF and NF. Artificial neural networks have proven to be excellent predictive tools in various petroleum-engineering applications. The excellent predictive capability of artificial neural networks comes from the fact that neural networks have large degrees of freedom that allows them to capture the non-linearity of the system being studied better than conventional regression techniques. The back-propagation neural network (BPNN) and probabilistic neural network (PNN) which display strong mapping ability are chosen to establish the prediction models. These models can be used to predict whether a HF will cross, dilate or slip into a NF under certain conditions, i.e. under different approach angles, different differential horizontal stress, net pressure and so on. Results have shown accuracy in predicting the interaction pattern.

Conventional HF design is based on the assumption that the rock is homogeneous and the fracture propagates symmetrically in a plane perpendicular to the minimum stress. In naturally fractured reservoirs due to interaction with NF, the fracture may propagate asymmetrically or in multiple strands or segments. The result from this work can be applied to estimate the interaction picture thus update and optimize the fracturing design.
Vietnam Offshore Operator Improved Production After Fracturing by Pumping Proppant Utilizing Seawater-Based Fluid
Authors: Tran V. V. , Duong L. D. , Nguyen D. Q. , Makmun A. , Tran L. T. , Teng L. K. , Feng E. V.
Published: October 2015

Conventionally, most offshore hydraulic fracturing treatments have been performed with fluid systems using fresh water as the base fluid. Problems arise when the volume of fluid required for the treatment is more than the vessel carrying capacity or when freshwater loading time can cause nonproductive time (NPT). Also, logistical and design issues when using fresh water, such deck load limitations restricting the amount of proppant and chemicals that can be loaded. In 2014, a service company and Vietsovpetro planned hydraulic fracturing in White Tiger field, offshore Vietnam. The plan was to pump a seawater-based fracturing fluid to allow pumping a bigger treatment than that allowed with fresh water to improve production and minimize water cut after treatment while maintaining a small vessel footprint.

This paper analyzes the advantage of the seawater-based fluid in enabling the fracturing equipment setup to pump more proppant than with fresh water, regardless of the vessel's capacity limitation. Using seawater-based fluid improved operational efficiency, resulting in cost savings. This paper describes the changes made to the fluid with time, in terms of reducing gel loading and increasing breaker concentration, to yield higher production. This paper also shows the relation between production and proppant amount introduced to formation.

The highest proppant placement in the formation was 265,000 lbm compared to 160,000 lbm with freshwater-based fluid in the past. Seawater-based fluid improved operational efficiency by eliminating NPT caused by transferring fresh water to vessel, water contamination, mixing KCl, and reducing turnover time between two wells to 24 hr. It was the first application of high-temperature, crosslinked, water-base fracturing fluids with delayed crosslink using seawater for hydraulic fracturing over a wide range of well temperatures from 174 to 284°F. A total of nine jobs in seven wells were pumped successfully without a single screenout. The production gain correlates very well with the gel loading and breaker loading improvement as well as other fracturing engineering aspects applied during campaign. Production increased by 65% compared to the previous year, corresponding to fold of increase (FOI) ratio of 1.8, which is 38% higher than that of the previous year.

Using seawater-based fracturing fluid has proven to be a solution to pumping of larger treatments than are possible with fresh water in a constrained offshore environment to achieve higher oil production rates after treatment.
Lesson Learned and Drilling Improvements Experienced From Matindok Gas Well Drilling Campaign
Authors: Hendrazid Hendrazid , Yulianto Irwan , Kurniawan Syaiful , Utomo Sukardono
Published: October 2015

This paper will be discussing about drilling operation of the Matindok Gas Development Project (MGDP) of PT Pertamina-EP that was developed in order that the gas consumptions of Eastern Indonesia territorial could be well fulfilled. Lost circulation & kick problem with major content of H2S and CO2 that were potentially expected to be drilling hazard at Manahaki formation of the field, therefore it would be a great challenge to be discussed on this paper.

Matindok Field had been developed since the POD (Plan of Development) was approved in year 2008 after this Matindok gas field was discovered with predicted IGIP of 347 BCFG. There were totally 7 delineation/development wells that were drilled under MGD Project. The latest well (Well #8) was completed and tested with the results of 10.671 MMSCFD, 149.99 BCPD from Menahaki Formation and 20.23 MMSCFD from the other previous completed well (Well #6).

Since to drill the Matindok wells have consisted of several drilling hazard (such as, shallow gas, lost zone and high pressure zone) therefore the drilling program of the wells required a thorough preparation on drilling engineering (i.e studies and evaluations) before PT. Pertamina-EP able to prepare all the matter concern with the execution of drilling operations. Lesson learned that was encountered on the earliest wells that were drilled had been evaluated in order eliminated all potential drawbacks as experienced, Therefore drilling performances can be improved. Detail operational drawbacks and evaluations process to results significant drilling performance improvement from one wells to other consecutive wells will be discussed in detail on this paper.

Drilling cost of the Well #6 indicated significant improvement had been well achieved. Drilling Division of PT Pertamina-EP had spent only around 66 % of the approved AFE budget of the well to complete the well and zero non-productive time (NPT) record was achieved when drilling the well (Well #8).
CASE Study: Enhancing CBL Quality through Emphasizing on Cementing Best Practice and Expanding Agent System
Authors: Bratadjaja E. , Inayah F. , Pasteris M. , Widyarsa I. , Ardhanareswari S. A.
Published: October 2015

Zonal isolation is an important thing to acquire good cement integrity. One of many ways to evaluate this is by running Cement Bond Log (CBL). Well condition prior, during, and after cement placement contribute high impact on the result of CBL. Aside from that, temperature and pressure changes also give significant outcome to CBL result. In this paper, some improvements wereapplied and the logging results showed significant impact on zonal isolation compare to previous well.

Objectives of this paper include improvement applied on case studies to obtain good zonal isolation and no remedial cementing required, emphasizing on applied cementing best practice recommendation, and introducing expanding agent in order to recover micro annulus.

Well integrity is a vital element to have long well life cycle. The paper describes the enhancementfrom poor zone isolation in previous well to be better in next well and this became one of best practices of cementing design and execution for Operator.

Improvement in mud removal was done by adding spacer volume with high concentration of turbulent spacer. Cement slurry had expanding agent in the system and smart retarder which provided better compressive strength. Improvements in cement system were seen in faster compressive strength build up and ability to recover micro annulus. Linear expansion result from expanding test is 80 μm in 7 days, which is sufficientto cover micro annulus that has happened before in previous well. The designed slurry was also supported by using more centralizers in execution. Quality check was done by measuring rheology of drilling mud and spacer. Cementing job was executed with no issues and following job program. Evaluation of cement job supported with the playback pressure data. Result of CBL result showed that good bonding was achieved on upper and lower side of interest zone.
Upstream Oil Industry Country Attractiveness Assessment By Integrating Potential Value and Risk
Authors: Sitompul Yosef
Published: October 2015

The oil industry is still an interesting sector to invest as the world's current oil reserves and production continue to show an upward trend despite the fact that oil is unrenewable resource. There are various methods to assess the value and the risk of investment in the upstream oil industry such as described in the SPE Paper from Widjadono (1993), Dharmadji (2002), Rajan (2008), and Craig (2004). However, these assessments are frequently done separately resulting in two different perspectives of investing in a country; the value and risk. This paper aggregates the study of value and risk as a single result in order to assist oil companies analyzing and comparing the country attractiveness objectively. Two approaches with completely different inputs and methodologies are used to assess the country risk. The first is the country risk score method which focuses on the country risk index observed by independent parties, such as corruption, terrorism, ease of starting business, etc. The second method is the Damodaran method which relies on financial market data of the country such as equity market volatility and country credit default swap rate. As a result, this paper will compare the combined value and risk results and analyze if the result from the two methods are validating or conflicting each other.
Importance of Condition and Performance Monitoring to Maximize Subsea Production System Availability
Authors: Chze Leong Pei
Published: October 2015

Today's subsea control systems generate vast amounts of data that can be used to help increase productivity, integrity, and safety of the subsea production system, however the key question is; is all of the available data being fully utilized for this purpose? In majority of cases, the answer is sadly no. This paper will illustrate how remote condition and performance monitoring of the subsea production system enables a predictive, condition based maintenance instead of reactive maintenance.

Condition and performance monitoring takes all subsea process and housekeeping data in real time; processes and integrates it with mathematical models in order to identify the equipment's condition. In addition, technical condition indices (0-100% values) are assigned to rapidly detect deterioration and aggregate equipments to provide an overall system condition. The solution is essential to be combined with experienced engineering support for consideration of equipment's criticality, past experience and equipment's operating philosophy.

Monitoring production has historically been the operators’ main focus - knowing that a well produces and how a reservoir performs are arguably more important than knowing the integrity of the subsea equipment. This narrow focus, however has led to a down prioritization of equipment related data and a number of maintenance planning and integrity issues. Condition and performance monitoring provides a solution for operators to fully utilize available subsea and topside data in order to increase productivity and minimize downtime.

This paper illustrates the benefits of condition and performance monitoring which enables proactive and predictive maintenance by providing operators with an early warning when the equipment starts to decline while still in operation, thus providing time for corrective action to be planned with minimal disruption to production. With the capability of remote surveillance and utilization of existing instrumentations and equipments, condition and performance monitoring solution can conveniently be implemented on both new and mature fields. Field case studies will be shared to illustrate how condition and performance monitoring solutions have been successfully implemented in previous projects.
Coiled Tubing Gas Lift Design and Troubleshooting - Case History
Authors: Edy I Ketut , Wicaksono Danang N. , Saputra Reza , Anantokusumo Ferry
Published: October 2015

VICO Indonesia is an Oil and Gas company which has operated mature fields located in the onshore part of East Kalimantan which has been on production for over 30 years. The fields are dominated by gas reservoirs with a much lower presence of oil reservoirs. Production mechanisms cover from natural depletion to weak and strong water drive, particularly in some of the shallow areas. Recent well completions include single and dual slimhole monobore.

The field is a perfect combination of stratigraphic and structural traps with more than 4000 sandstone reservoirs where around 450 of those are oil reservoirs. The oil recovery factor for these reservoirs is in the range of 10-30%. Oil development in this fields performed using gas lift as the main artificial lift while several wells still flowing naturally. Coiled tubing gas lifted (CTGL) wells contributes to 60-80% of current oil production of 8000 BOPD.

Totally, 50 CTGLs have been installed in VICO Indonesia where most of those considered successful. The main problem found related with initial operation after installation. Lesson learned has been summarized including the design and the procedure for initial operation. Coiled tubing gas lift design and troubleshooting are rarely found in literature. Thus, this paper presents the detail step by step design and how to troubleshoot the possible failure during early operation. This approach exhibits a real benefit to recover more untapped hydrocarbon with more aggressive program.
Application of High Performance Water Base Mud in Kintom Formation at North Senoro Drilling Gas Development Project
Authors: Hadinata Dwie , Mansur Deutra , Rahmadona Desmawati
Published: October 2015

North Senoro Gas Field is located onshore, operated by JOB PERTAMINA – Medco E&P Tomori Sulawesi. The aim of North Senoro Development is to produce gas from limestone reservoir (Mentawa reef), member of Minahaki formation to fulfill gas supply commitment to Donggi Senoro LNG Plant. First spud of drilling operations was on 16 September 2013 at "well F". One of the drilled formations in Senoro Field is Kintom formation, which is dominated by quite reactive clay with sandstone insertion and limestone. Some swelling clay related problems has been quite often encountered when exploration wells drilling took place. It was also backed up by the CEC (Cation Exchange Capacity) test data done on cutting from Kintom formation, which gave the value of 20 meq/100g. However, the well-sites for upcoming wells are surrounded by people and rice paddy field, making environment impact is a critical point in drilling mud selection. Therefore, by assessing all those critical expected requirements out of the drilling mud, it was decided to use High Performance Water Base mud system to drill Kintom formation.

Various water-based drilling fluid type with various type of chemical for clay inhibition were assessed. However, the mud was expected to also have a very minimum Chloride content. This value should be very low that it should not have a significant impact on surrounding environment. From selection and laboratorium process, the approved shale inhibitor on this mud system was Ultrahib. The Ultrahib inhibitor is a liquid additive that acts as a clay hydration suppressant by intercalating and reducing the space between clay platelets so that water molecules will not penetrate and cause shale swelling. This paper will cover, from planning phase to operational phase, how Ultrahib performed and how an optimized concentration of Ultrahib that was adjusted along the way, could overcome the challenge of clay.
Design of Experiment and Statistical Approach to Optimize New Zone Behind Pipe Opportunity: North Roger Block Case Study
Authors: Jati Nugroho , Rahman Fatkhur , Kurniawan Hendri , Sari Zakiyah Fajar , Puspasari Siska
Published: October 2015

The pursuit of oil recovery enhancement is an important matter in petroleum industry. Besides explore and exploit new opportunities, the optimization of existing well through New-Zone-behind-Pipe (NZBP) is one of the main tools to optimize brown field production. North Area of Roger Block, in Central Sumatera, consists of several brown fields; still have opportunities for production enhancement through NZBP candidacy optimization. Abundant unperforated zones were still unproduced due to difficulty in evaluating and prioritizing remaining NZBP prospects. Recently, there is no standardized method to prioritized NZBP opportunities. Therefore, this study was conducted to improve understanding of reservoir for NZBP ranking, and also develop selection criteria with objective to increase success rate. Furthermore, enhancing field performance by executing NZBP will be achievable.

To develop screening process, this study is implementing Lean Sigma statistical tools such as CNX, Pareto, and scatter plot to define and improve NZBP selection process. This study also implemented Design of Experiment (DOE, related to statistics) methods to evaluate dependency between reservoir dynamic parameters and NZBP result. The result itself then came up with 4 major parameters which are most influential to NZBP historical oil gain result: water cut, sand thickness, resistivity, and permeability. In addition, a scientific cut off for each of those parameters were introduced for ranking the existing NZBP candidates empirically and statistically. After generating a screening process, the next step is to build reliable forecasting methods for future NZBP job. Therefore, we utilize the equation resulted from previous multi-variable linear regression and 2nd degree polynomial regression to estimate oil gain.

This process is currently in place and results enormous financial revenue up to 9.4 MMUSD within 1 year. It has successfully increased success ratio to 70% and increase average oil gain by 246%. Lesson learned from this study was the development of good screening process to improve the candidacy. There is a big opportunity to adopt and adapt this small yet significant effort to other field worldwide.
Production Data Analysis: Estimating OGIP and Forecasting Gas Production Profile From Rough Data of Over-Pressured Gas Reservoir
Authors: Arif Rahman H. , Yusni Aditiah R. , Panca Suci W. , Eldias Anjar P. , Tri Adi Arifianto , Subihi Eka P.
Published: October 2015

Original Gas in Place (OGIP) is important in Reservoir Engineering. Many methods have been developed to reduce uncertainty in estimates of OGIP. Limitations from earlier methods have been overcome by new methods. This inspires reservoir engineers to make sure they estimate the true OGIP of their Gas Reservoir.

Before starting with analysis, the most important thing to be remembered for all reservoir engineers is the quality of data collection. As people say: junk in equals junk out. So a good reservoir engineer will take the longest time in data diagnostics and validation.

OGIP estimation based on production data analysis such as P/Z plots is a well-established technique. However, it can yield the wrong OGIP if we don’t account for the drive mechanism of the reservoir, especially for water drive reservoirs and over-pressured gas reservoirs.

The Melibur gas field has been producing gas from an over-pressured reservoir (10.5ppg at 570 feet) since 2002. The company delivers 0.3 MMSCFD for power generation to the local community as part of the company‘s commitment to CSR.

In this paper, we will discuss estimation of OGIP of over-pressured gas reservoirs using modern production data analysis, and forecast the gas production profile using a single tank model. Firstly, production data diagnostics were applied using Blasingame type curves, and then flowing material balance to gain confidence in OGIP and deliverability. These results were input into a single tank model, which was used to forecast the gas production profile to ensure the existing field development can meet the GSA.

This analysis gave us a new OGIP and more reliable production forecast. It also gave us a new point of view on analyzing production data in over-pressured gas reservoirs.
Reduce-Reuse-Recycle Approach in Managing Onshore Drilling Waste in North Senoro Drilling Gas Field Development Project
Authors: Ratri Widodo Andreas Krisbayu , Rahmadona Desmawati , Gunawan Hendra
Published: October 2015

Senoro, an onshore major gas-condensate field in East Indonesia, on the eastern arm of Sulawesi Island, is operated by JOB PERTAMINA – Medco E&P Tomori Sulawesi. Drilling campaign of 2013 – 2014 was carried out to drill 12 wells at four clusters which consist of 4 re-entry wells and 8 new development wells in North Senoro Gas Field.

By utilizing Water Base Mud as the drilling fluid for the overall well sections, the drilling operations generated two primary types of wastes – solid waste and liquid waste. Solid wastes consist of drilling cutting; used drilling fluid in its solid phase and contaminated packaging materials. Whereas liquid wastes consist of used organic chemical and the drilling waste water produced from fluid dewatering system.

Under the Governmental of Indonesia Regulation no.18 JO 85/1999 regarding Hazardous and Toxic Waste Management; drilling cutting and used drilling fluid were categorized as hazardous waste with code D220, the used organic chemical and contaminated packaging were categorized as hazardous also by the law definition, hence it required specific treatments in managing the drilling waste. Drilling waste water was required to be managed under the discharge limitation regulation of Act of Ministry of Environment no. 10/2010.

In this case study through a waste minimization concept, reduce-reuse-recycle approach is utilized to manage the produced drilling waste. Initiated by an engineering design that was taken thorough deep assessment to use to use water base and non-chloride content mud material, drilling waste management flow diagram is then developed and applied to manage waste related to the drilled well; general solid waste and general liquid waste.

By applying the selected drilling waste management flow diagram, the North Senoro drilling campaign can be performed within the waste minimization concept and all discharged parameters can be ensured within the regulation discharge limit.
Drilling Efficiency and Geological Restrictions in Carbonate Type Collector with MPD in Compare with Conventional Methods
Authors: Kulikov S. , Priymachenko D. , Bakhtin A. , Shilkin P.
Published: October 2015

Riphean anisotropic cavernous-fissured carbonate reservoirs of oilfield at East Siberia area – one of the most problematic objects of oil and gas production described in this article. Here is discussed geological substantiation and first result of new technology involving in drilling of Riphean carbonate reservoirs with "Controlled pressure technology" by recovery wells with horizontal bottom at the oil-gas condensate field in Evenki Region. Comparison results of conventional drilling and "MPD" (Managed Pressure Drilling) technology.

Riphean reservoirs drilling process could be provided in two options.

The first one – horizontal conventional drilling. As far as the bit penetrates into the reservoir we are seeing SPP (Stand Pipe Pressure) decrease which means we have total lost circulation. There was only one means for resolving this problem – using LCM (Lost Circulation Material). Due to complicated geology and high parameter of gas factor in Riphean reservoirs (losses while circulation/ gains while static), LCM was insufficient solution.

The second is to perform drilling process using MPD (Managed Pressure Drilling) technology. We have the advantage using lower mud weight compared with conventional drilling. MPD technology corresponds with geological conditions of Riphean reservoirs and can be more profitable in future production from these wells.

MPD technology with closed loop circulation system showed that we can "manage" BHP (Bottom Hole Pressure) and it really works in temperature conditions of 45 Celsius below zero in Evenki Region (East Siberia). In practice we have seen, that it was possible to achieve more gentle management of BHP than with conventional drilling using LCM. Also with "MPD" system in this oilfield we were able to drill the first ERD (Extended Reach Drilling) well. However, even with such extended horizontal section (1000 meters), a significant reduction of losses was achieved without using LCM. Total results of MPD technology we will see after DST (Drill Stem Test) of drilled wells.

New technology showed that it was a right choice to use close loop system and MPD. Also for drilling new wells in this Riphean carbonate reservoirs of this oilfield area we will use this experience. Best way to reduce catastrophic losses in abnormally low pressure reservoir conditions is reduce and control the ECD and details how to achieve it we have considered in this article.

The results: Reduced interval construction time. From 31 days to 24 days.Reduced fluid loss during drilling. From 2000 m3 to 1200 m3.Improved the operational safety by closing the loop and real time early kick and loss detection.
Cased Hole Ceramic Screen Cutting Completion Cost for Marginal Reservoir : Application in Tunu Field
Authors: Risatrio A. A. , Muryanto B. H. , Wijaya R. , Styward B. , Jackson R. , Gundemoni B. R.
Published: October 2015

Shallow gas development in Tunu field, East Kalimantan, Indonesia requires cost effective solution to safely produce multi layered sand prone reservoirs while maintaining low completion cost. Gravel pack solution has been deployed since 2006 and it enables producing small layers with multi zone single trip gravel pack system. However the system reaches its technical limits in term of cost, number of completed zones and well deviation. Developing alternative sand control solution is required to produce small marginal reservoirs and maximize recovery while maintaining robust sand control. Ceramic screen is considered as emerging alternative solution to cut sand control cost for marginal reservoirs. Ceramic material provides far superior erosion resistant compared to standard metallic screen. The paper will present the design of ceramic screen for cased hole Stand Alone Screen (SAS), its deployment in three Tunu wells and the production result from the completed reservoirs.
Full Field Integrated Modelling Throughout Life-Cycle Phases of Field Development : A Subsea Processing Case Study
Authors: Dianita Sandy , Gandi Rahmawan Setyadi
Published: October 2015

Traditional multiphase flow simulations often include less rigorous boundary condition assumptions, because flowline models are commonly isolated from both upstream well inflow and downstream processing facilities. Such an approach can be even more unrealistic if the flowline model network is complicated for example, where connected with subsea processing equipment. Within this kind of system, changes in fluid behavior are even more sensitive to overall operability. A full field integrated simulation, which includes well inflow, subsea equipment (XTs and manifolds), subsea processing, flowlines, and/or arriving facilities, offers a more realistic solution. This paper describes the application and value of performing full field integrated simulations throughout the life-cycle phases of field development.

The solver used for the simulation provides a powerful tool to screen design alternatives to identify the optimal field solution in a cost efficient way at an early design phase. In the detailed design phase the dynamic simulations using the same full field model can be performed to ensure system operability. Similarly, in the life-of-field operation phase, the same full field model can be used to perform real time metering and monitoring as well as "look-ahead" forecasting as part of an advisory system. This is usually instrumental for a challenging field production.

As the simulation model evolves since early design phase until the life-of-field operation, it promotes a comprehensive continuity. "One model one solution" provides an effective design and operation tool. Such a tool is able to provide a wide range of information that is relevant across multidisciplinary teams.