bluuebunny/crossref_metadata_2025 huggingface dataset:
Drilling Record ERD Wells at Yamal Region
Authors: Glebov Evgeny , Shokarev Ivan , Boroday Aleksey , Grigoryev Maxim , Gulov Artur , Zhludov Aleksey , Chetverikov Dmitry , Dymov Sergey , Dobrokhleb Pavel , Ablaev Anton , Yakovlev Alexander , Petrakov Yuri , Sobolev Aleksey , Korelsky Evgeny , Zadvornov Dmitry , Zavarygin Sergey , Sulimov Dmitry , Kuzakov Vitaly , Alexandrova Anna , Perkshev Dmitry , Makhambetov Amangeldy , Urmantseva Lena , Leontyev Dmitry , Belyaev Aleksey , Shirshov Anton , Shakirov Eduard , Kovalev Alexey , Gainullin Marat
Published: September 2014

The interaction of NOVATEK, Investgeoservice (IGS) and Schlumberger allowed to deliver 2 complex extended reach wells (ERD), including the longest ever drilled in Russian mainland, well number 373, in the Yurkharovskoye field located in Arctic Yamal peninsula, as part of the offshore development plan from onshore locations.

A geomechanical model was developed to address the main challenges, including optimum equivalent circulating density window and drilling regimes for wellbore quality and stability.

Drilling & Measurements key technologies, multipole sonic-while-drilling, latest high-speed telemetry service, multifunction logging-while drilling technologies were used for real time Geomechanics service to prevent costly wellbore stability issues. In addition the combination of rotary steerable technology with customized polycrystalline diamond compact bits and drilling fluid system, delivered superior drilling performance, resulting in high performed drilling of these complex wells.

Positive experience in the construction of these ERD wells, gives grounds to include options for developing the region, similar wells in the planning stage of various development scenarios.

This article devoted to the description of technologies and solutions that have been used for the construction of these wells.
Synergizing Managed Pressure Drilling, Pore Pressure Prediction and In-Line Gas Chromatography Technologies for Enhanced Formation Evaluation of Exploration Wells
Authors: Norcross Dean , Fisher Kevin , Morrison Alan , Wuest Chad Henry , Bamborough Edward , Toralde Julmar Shaun
Published: September 2014

Exploration wells normally employ a gamut of advanced well construction and formation evaluation technologies to be able to ensure the success of the operation. Among these technologies are managed pressure drilling (MPD), pore pressure prediction (PPP) and in-line gas chromatography (IGC). However, since these technologies normally belongs with different end users, with PPP and IGC under the purview of the geologists and MPD with the drilling department, the full utilization of the combined capabilities of these technologies have yet to be realized.

MPD, PPP and IGC techniques can be combined to enhance and increase the information collected about the formations being drilled. This paper describes how the advanced flow detection capabilities of MPD can be utilized to safely allow for the collection of data required for PPP purposes and even enable verification of predicted values and the collection of additional pore pressure information. It also details how IGC in tandem with MPD can further enhance data collection by enabling full characterization of the events detected by the MPD system, instead of losing the same at the mud – gas separator, whenever flow is routed there as a precaution. Conversely, this also provides validation for the events detected by the MPD equipment thereby minimizing the chances of having false alarms with the system.

When synergized, MPD, PPP and IGC technologies have the potential to greatly enhance the characterization and evaluation of wells, especially those drilled for exploration purposes.
Successful Application of Diagnostic Interventions for Well Revival: A Case Study
Authors: Singhal JOY , Goenka Sharad Kumar , Kothiyal Manish Dutt , Parasher Arunabh
Published: September 2014

Field X in India has been developed as an onshore field wherein wells are drilled in shallow reservoir. There are approximately 110 oil producers and 60 water injectors in this field. To mitigate sand production, wells have been completed with standalone screens (including conventional, SSD & ICD). Crude of the reservoir is high in wax content with pour point at 50 oC.

This paper highlights a case study on one of the oil producer X-A which was drilled & completed as 4-1/2” standalone screen completions to ensure selective production from various sands. Post completion, in all the subsequent rigless interventions conducted in the well X-A, an obstruction was observed against one of the Screen SSD. Initially a scale build up or a sand bridge was suspected at the obstruction depth, but well bore clean out with coiled tubing intervention failed to clear it off and pass through. Also, communication was suspected between tubing & tubing-production casing annulus. In view of above, the well was kept shut-in for more than a year.

This well, therefore became a critical case wherein application of Downhole Video Camera detected the potential leak in the tubing above the production packer and buckling of lower completion. Further, the Production Logging Survey confirmed the leak in the tubing. Based on the above field observations a CT conveyed Taper milling was conducted to clear off the obstruction post which work-over was conducted for upper completion.

This paper details the collaborative approach of diagnostic and troubleshooting interventions planned in the well X-A, challenges involved in the same and lessons learnt during the whole operation, which finally helped in bringing the well online successfully and affordably, avoiding numerous time and money consuming interventions which could have been carried out in absence of detailed root cause analysis of the problem.

Introduction

Well X-A is a deviated oil producer in field X. Post completion of the well, during attempts to flow back the well, an obstruction was observed around one of the screen SSDs which prevented any well intervention to bring the lower zones on production. Several conventional attempts were made by slickline & coiled tubing to clear the obstruction but all interventions were in vain and no success was observed. In addition to failure to clear the obstruction, these conventional methods also failed to provide clear indication regarding the cause & type of obstruction. Further sections of the paper highlight the well investigation with Downhole Video Camera technology and then clearance of obstruction with Coiled Tubing conveyed Thru-Tubing Tapered Mill.
Increasing Sales Gas Output from Glycol Dehydration Plants
Authors: Dreher Trina , Cavill Michael , Geard Adam
Published: September 2014

Natural gas contains significant amounts of water that must be removed. A common way to dehydrate gas to low water levels is via a liquid desiccant such as tri-ethylene glycol (TEG) and the use of stripping gas in the regeneration system.

The patented GLYNOXX® recycle stripping gas process offers a solution to obtaining enhanced gas dehydration without wasting valuable product. In this process a small amount of stripping gas is introduced into the stripping column, which once it passes through the column is cooled to condense and separate the majority of water. The stripping gas is then recycled to the stripping column via a blower. The stripping gas used is preferably flash gas, although if sufficient quantities are not available then fuel gas may be used. Regardless of the type of stripping gas employed, the recycle process ensures that only very small make-up quantities are required on a continual basis thereby decreasing the amount of fuel gas consumed during operation. An additional advantage of the GLYNOXX process is that it reduces the amount of gas vented from a TEG dehydration plant thereby reducing the carbon emissions liability of the plant.

The GLYNOXX process may be integrated into a new TEG dehydration plant or retrofitted to an existing TEG dehydration plant. This paper details the GLYNOXX design and how it is integrated into both new and existing plants. It then compares the operation of an existing TEG dehydration plant that employs standard stripping gas operation with that of the GLYNOXX process following a retrofit, including the required plant modifications. A simplified economic analysis is presented for a retrofitted GLYNOXX process to illustrate the significant advantages of the technology for TEG dehydration plant operators.
HPHT Hydraulic Fracturing Proving Late Jurassic Cretaceous Petroleum System Reserved at Krishna Godavari Basin
Authors: Barasia Ankur , Sharma Amit , Shado Olushola , Deshpande Vaibhav , Srivastav Saurabh , Singh Mukund Murari , Tiwari Shobhit , Ranjan Vishal , Ranjan Amit
Published: September 2014

Between 2010 to 2013, three onshore appraisals well are drilled in the southern part of KG Basin, aiming to appraise economical potential of oil reserved from Late Jurassic Cretaceous petroleum system. Some of the major inherent challenges of this region are to complete and test the wells with very tight deep sands and HPHT operations.

The target reservoir consists of two distinct pay zones, the lower part is G formation which consists mainly siltstones, and the upper part is cleaner R sandstone. Total thickness of primary target zone of interest is more than 200 m with average permeability of less than 0.1 mD. Open hole log indicated water saturation in G formation to range between 20% to 60% while in R formation saturation range was between 40 to 70%. Initial exploratory test showed no significant flow of hydrocarbon therefore hydraulic fracturing program was proposed and planned as the enabler to facilitate production at economic rates from these reservoirs.

Detailed petro-physical and geo-mechanical formation evaluation with Mechanical Earth Modeling, reservoir evaluation using Injection Fall off test and fracture height estimation using Planar 3D models are some of the tools used to ensure a successful stimulation job across a 200 m thick G formation which appeared to have no significant stress contrasts to confine individual fracture treatments. The hydraulic fracturing project workflow includes selecting right perforation strategy, optimizing number of fracturing treatment and minimizing fracture interference. Proper data interpretation, meticulous planning and detailed engineering analyses and design overcome these challenges, which lead to successful hydraulic fracturing completion of all the wells in the campaign with encouraging well production test results and thus confirming the presence and commerciality of hydrocarbons in this field.

This paper details the technical analysis and engineering workflow used as tools for a successful hydraulic fracturing of G and R formation. Design, Execution and Evaluation process used during hydraulic fracturing is also discussed. In the end, lessons learned and recommended workflow to explore similar reservoir in the future have been captured.
Preventing String Integrity Failure in Production and Stimulation for High Temperature Wells
Authors: Aditya Gama Hafizh , Subiantoro Edy
Published: September 2014

String integrity is essential for successful production and stimulation.

With production, string integrity means pressure integrity of packers and sliding-sleeve-doors commonly used to isolate target production zones. With hydraulic-fracture stimulation, frac-string integrity is mostly concerned with the burst pressure of the string, packer load and string friction, which depend on fluid rate and pump pressure.

In high-temperature wells, things get more complex. High rate producers heat the production string far above the normal gradient temperature, and so it expands. With frac strings, the opposite occurs. Injected water cools the string far below the normal gradient temperature, and so it shrinks. Both situations create additional string integrity issues.

In 2008, EMP Malacca Strait drilled and completed (as selective singles) three infill wells in Kurau, a mature oil field in Sumatra, Indonesia. Later, when changing ones, the completion string was found to be buckled. An impression Block showed an obstruction inside the tubing. This zone could not be changed.

In the same year, we performed our first hydraulic-fracture-stimulation campaign in the Kuat oil field, of sandstone reservoirs at 320 degF. During the first job, the frac string failed during the data-frac, as seen by the sudden increase in annulus pressure. We suspected the packer unset due to high shear load from frac-string thermal shrinkage.

Both these string failures occurred, despite standard shrinkage calculation suggesting there should be no issues.

The paper investigates elongation and shrinkage of production and frac strings using a finite difference-mathematical model. The study found a much higher thermal expansion factor than from a standard calculation, and so we started to use expansion joints for both selective completions and for fracture-stimulation campaigns.

Since this time, we have suffered no further string failures.
Application of Velocity-Dependent Relative Permeability for Modeling Gas-Condensate Reservoirs: Field Example
Authors: Tani Kengo , Yamada Tatsuya , Ikeda Shuichiro
Published: September 2014

In recent years there has been a growing interest in accurately modelling the condensate banking phenomena in gas-condensate reservoirs to better predict production performances. The velocity-dependent relative permeability (VDRP) concept is one of the methodologies to replicate well production performance reflecting both condensate banking phenomena and velocity effect in gas-condensate reservoirs. In this paper, we present the result of a fine-scale compositional reservoir simulation study by introducing VDRP model validated against the actual field production data from a gas-condensate reservoir called S-Tuff Formation in Minami-Nagaoka Gas Field in Japan.

A comprehensive data acquisition program was implemented during the long-term production test of the S-Tuff formation to enable the detailed evaluation of production performance and near-wellbore fluid behavior in the reservoir. The program included the measurements of flowing and shut-in bottomhole pressures, surface flow data and fluid sampling. The ultimate objective was to accurately predict the field production performance by an established reservoir simulation model through history matching.

The fine-scale compositional reservoir simulation study showed that VDRP model was required to obtain reasonable match with production data, including BHPs and GOR, whilst it was not achieved by the model with conventional gas-oil relative permeability curves because the simulated FBHP fell far below the observed data when the FBHP was below dewpoint. Hence, the study suggested that improvement of gas-oil relative permeability by velocity effect occurred during production. It was also shown that the well productivity impairment due to condensate banking in VDRP model was not as severe as in the case where the conventional fixed gas-oil relative permeability was used.

In this study, the VDRP concept was adopted to evaluate the impact of condensate banking and velocity effect, and its methodology was validated using the actual field production data and its history matching. This study will contribute further improvement of performance prediction for similar gas-condensate reservoirs.
Formation Tester Optimization for the XiHu Basin: Observations and Case Studies from the East China Sea
Authors: Shi Rongfu , Wang Jianping , Liu Daneng , Zhang Guodong , Tellapaneni Prasanna , ChengGang Xian , Chen Jichao , Yu Yin Hua
Published: September 2014

In recent years, low-porosity and -permeability gas reservoirs have become an important exploration target for the industry in general, and the China National Oil Company (CNOOC), Shanghai branch, in particular. Formation evaluation of these resources is inherently challenging, and the application of formation testers has become an integral part of the evaluation workflow to address these challenges.

The XiHu basin, located offshore China in the East China Sea, is a frontier exploration area for CNOOC Shanghai branch. Drilling safety in the XiHu basin is a concern owing to the intermediate high-pressure sands and overlying coals. Drilling with high overbalance and long openhole sections to mitigate these challenges has in turn caused problems for the formation testing program that are manifested as elevated pressures and long sampling times.

The optimization of formation testing began with the statistical analysis of historical data to identify trends in pressure measurement and sampling. This analysis clearly indicated that continuous filtrate invasion and water slumping processes contributed significantly to the long sampling times and apparent elevated pressures observed. Therefore, these mechanisms were studied by modeling the invasion process quantitatively using a finite-difference simulator. After matching the simulated pressures with measured pressures in a candidate well, the effect of these invasion mechanisms on the formation testing program and ways to mitigate them was investigated.

Our study shows that the invasion profile in these reservoirs is different from the classic invasion profile. The classic model shows minimal invasion at the top of the sand, but we observed the longest cleanup times were generally at the top of the reservoir. Using realistic physical and drilling parameters, we demonstrate that invasion effects are often more complicated than the classic model.

Optimized tool selection and testing processes have been proposed to mitigate the effects of the invasion processes. The applicability of new technology in these challenging environments was also studied and demonstrated through case studies in which an overall efficiency improvement in the formation testing program was observed.
Gas Turbine Power Generation Utilising Low and Variable Quality Gas Fuels in Dry Low Emissions Combustion Systems
Authors: Welch Michael
Published: September 2014

Since the late 1980s, environmental concerns over pollutants created during the combustion process have driven gas turbine manufacturers to develop combustion systems that create lower and lower emissions of nitrous oxides (NOx), carbon monoxide (CO) and unburned hydrocarbons (UHC). To meet this challenge, manufacturers developed Dry Low Emissions (DLE) or Dry Low NOx (DLN) combustion systems. Primarily employed initially in industrial applications or utility power plant using pipeline quality natural gas as the main fuel, DLE became quickly established and is now a well-proven technology with thousands of units installed and tens of millions of operating hours experience gained. Some manufacturers now only offer DLE combustion systems on some gas turbine models, such is the confidence in this technology.

Upstream Oil & Gas operators face challenges that industrial users and utility companies don't: the gas fuel available is in most cases not ‘pipeline quality’, containing varying amounts of contaminants such as inert gases or higher hydrocarbon species; the gas composition can vary depending on both source and time; toxic and corrosive contaminants, such as hydrogen sulphide, might exist within the gas stream; with no connection to an electricity grid system, the gas turbines are required to operate at constantly varying loads to match the power demand of the facilities; and unit reliability is critical to ensure continuous production and revenue generation.

This paper reviews the work undertaken by Siemens Industrial Turbomachinery on their range of gas turbines between 5MW and 50MW in power output to characterize the capabilities of the DLE system with respect to the different fuel gas compositions encountered, and the variability of the gas composition, and discusses some examples of installations both in industry and offshore O&G applications where such fuels are used while still meeting the required emission limits and without affecting operability.
Improving Recovery Efficiency of Polymer Flooding for Middle and Low Permeability Reservoirs in Daqing Oilfield
Authors: Zhang Xiaoqin , Guan Wenting , Pan Feng
Published: September 2014

Daqing Oilfield is a heterogeneous sandstone reservoir with multiple layers. Polymer flooding in the primary oil layers has achieved significant technological and economic effects. And polymer flooding in the secondary oil layers of middle and low permeability (100~500mD) has began since 2003. Compared with the primary oil layers, the secondary are of thinner sand bodies, lower permeability, narrower channel sands and worse connection. For that reason, following measures are taken to improve the polymer flooding efficiency in these layers.

Layers are divided and those of similar properties are grouped to form development series. By doing so, layer differences are reduced and the recovery efficiency is enhanced.

Injector-producer spacing is shortened and the relationship between injection and production is optimized to improve the controlling degrees of polymer flooding

The right time and proper layers for measures of fracturing in producers and in-depth profile control in injectors are optimized to improve the effects of these measures.

By doing so, recovery efficiency of industrialized polymer flooding in the secondary oil layers is enhanced by 10%.
Advanced Production Operations Support Applying Dynamic Simulation Techniques – Blacktip Gas Field in Bonaparte Basin, Australia
Authors: Yokote Ryosuke , Yamada Tatsuya , Derrij Joseph , Maniscalco Giuseppe , Mantecon Juan Carlos
Published: September 2014

This paper describes the work flow adopted by Eni Australia to support Blacktip daily production operations. The Blacktip gas field is located offshore in the southern Bonaparte Basin, Australia. Eni Australia is the operator for the Blacktip gas field and holds 100 per cent (%) working interest. Production from the Blacktip gas field started in September 2009 and has been the primary source of gas for Darwin, Northern Territory. The Blacktip gas project consists of a normally unmanned Wellhead Platform (WHP) at a water depth of 50 meters (m), a 110 kilometer (km) offshore Gas Export Pipeline (GEP) and the onshore Yelcherr Gas Plant (YGP). Two deviated production wells were drilled and completed on the WHP in September 2009. Well intervention was carried out on the WHP to shut off a lower production zone and perforate the main production zone in June 2013. Untreated gas from the wells is directly sent to the YGP via the GEP, without offshore processing. The gas is treated at the YGP to meet the customer's specifications and it is sent to Darwin via an onshore gas transmission pipeline operated by a third party. Condensate is processed and stored at the YGP, and offloaded via a 10 km offshore offloading line.

Multiphase flow numerical transient simulation (dynamic simulation) techniques have been used to establish the work flow to support daily production operations. Three fit for purpose models have been constructed in order to fulfill this task in a timely manner. They are the well(s) model, the GEP model and the offloading line model. History matching of the GEP model has been routinely conducted to monitor pipeline performance and to provide the operations team with relevant information such as liquid volume in the GEP, slug prediction, etc. The condensate offloading line model was used to develop operational guidelines for the first offloading operations conducted in July 2010. In due course, dynamic simulations were applied to support well operations using well models. Regular history matching has been conducted to validate the models and monitor well performance. The well model was also used to establish a sound and safe operations plan for the well intervention campaign, to change the production zone. The application of dynamic simulation is now an integral part of daily production operations for the Blacktip gas field.
Drilling on Target: Saving Rig Time While Maximising Reservoir Exposure in a Horizontal Well
Authors: Hassan Siti Norhajar , Kassim M Shahril , Ariffin Ahmad Jazim , Oruganti Bhargava Ram , Santoso Gagok , Permanasari Dian , Alang Khairul Anuar , Yusuf Nora
Published: September 2014

A pilot hole is a commonly used method to reduce uncertainties while drilling a horizontal well, but it is a costly procedure. Thus, there is high demand in the industry to have alternative solutions to reduce total well cost but still achieve the well objectives. This paper presents a case study of a horizontal well in the Malay basin that was landed accurately in the target oil reservoir without any pilot hole and drilled optimally in the target layer with improved reservoir thickness evaluation.

The well target was a sand layer with average thickness of 3 to 5 m and variation in quality. Unlike the other target reservoirs in the field, there was no concern over fluid contacts within this sand; thus, options to eliminate a pilot hole were considered feasible. The main challenges were the structure determination, formation dips, and thin-sand thickness that would cause significant impact to landing accurately and achieving a minimum of 300-m lateral length inside the reservoir.

A full suite of logging-while-drilling (LWD) measurements, combined with a model-compare-update well-placement method, were used during landing to address these challenges. For the lateral section, an additional deep-directional resistivity measurement was used for boundary detection, which enabled proactive geosteering to avoid premature exit. As a result, the horizontal well was landed accurately in the target reservoir layer without the need for a pilot hole; thus, significantly reducing the well cost. Furthermore, a 500-m lateral section was maintained 100% inside the target reservoir, which exceeded the initial objective. A post-drilling analysis was performed using density image dip-picking and bed-boundary mapping results. The drilling polarity along the lateral section could then be determined and the true stratigraphic thickness of the target reservoir extracted, which resulted in a more accurate reservoir thickness evaluation. The methods and processes used in this case study yielded best practices and recommendations for drilling and evaluating similar reservoir conditions elsewhere.
Case Study: Factory Drilling Australia's Unconventional Coal Seam Gas
Authors: Smith Glenn , Waguih Ahmed , Redrup John , Kholgh Arman Nick , Aguirre Eduardo
Published: September 2014

The Queensland Curtis Liquefied Natural Gas (QCLNG) project is the world's first project to convert coal seam gas (CSG) into liquefied natural gas1. The project involves drilling thousands of wells in the Surat basin, installing an underground 540 km long pipeline to Gladstone and the building of a plant on Curtis Island to liquefy the natural gas. The project, which has been under construction since 2010, is on schedule to provide LNG for export from the end of 2014.

The multi-billion-dollar investment by QGC, the Australian business of BG Group, is one of Australia's largest current capital infrastructure projects. Schlumberger has been contracted to deliver on the drilling and completion phase of this critical project.

The "Factory Drilling*" project operates nine rigs using a multidisciplinary team consisting of project management staff utilising/coordinating logistics, warehousing, wellsite management, cementing, wireline, bits, solids control and directional services/personnel. The project has overcome significant challenges in the business development and start-up phases. Through the application of the "excellence in execution" philosophy, records have been broken and new performance benchmarks set in this unconventional CSG market.

Since the start of the project in early 2012, using the team's project management abilities and incorporating LEAN (the identification and steady elimination of waste from operations) initiatives, the project has drilled and completed more than 1000 wells, some in as little as 2.15 days (drilling time) and 1.04 days (completion time).

The optimisation initiatives have contributed towards reaching a state where the project is currently performing very close to the technical limit, yet challenges are still ahead to maintain and mature the safety culture and improve the operational efficiency even further.
Well Integrity - Moving from Firefighting to Strategic Planning
Authors: Ceray A. , Borzel K. , Spowage A. C.
Published: September 2014

A mature Well Integrity Management System (WIMS) is essential to assure the sustained integrity of a well. When adequate systems and processes are not in place the result is a reactive or firefighting approach to integrity management. An immature WIMS will typically result in a higher risk of a major incident occurring, an increased frequency and severity of minor integrity issues as well as reduced long term production.

Based on real world experience gained through the management of over 10,000 wells and the extensive experience of one of the largest well asset integrity management teams in the industry, the key common transformative elements required to move from a reactive to a strategic WIMS has been developed. A well integrity-focused maturity model is outlined and real world experience used to illustrate typical characteristics of organisations operating at each integrity management maturity level.

In order for companies to enhance their level of maturity a stepped roadmap approach is proposed. As the specific details of the path to a mature WIMS will be unique, this work identifies the common transformative elements and places them as milestones on the roadmap. A full roadmap will need to be populated with well specific details for each of these milestones. This will facilitate a company's progressive improvement to attain each level of WIMS maturing.
Prediction of Productivity Decline in Oil and Gas Wells Due to Fines Migration: Laboratory and Mathematical Modelling
Authors: Siqueira F. D. , Yang Y. , Vaz A. , You Z. , Bedrikovetsky P.
Published: September 2014

Suspension-colloidal transport in porous media with the particle detachment usually exhibits a significant permeability decline. It occurs due to mobilisation and migration of detached colloidal or suspended fines with their straining in thin pores of the rock. Numerous laboratory coreflood tests show that the time for permeability stabilisation counts for hundreds of injected pore volumes, while the classical filtration theory assumes the released fines transport by the bulk of the carrier fluid yielding one pore volume injection to stabilise the permeability. In the current paper, the stabilisation delay effect is explained by slow drift of the mobilised fines near to pore walls. The basic flow equations for a single-phase particle transport in porous media with velocity lower than the carrier fluid velocity are proposed, and the analytical model for one dimensional flow with particle release and straining under the piece wise increasing velocity is derived. The laboratory data are in a good agreement with the results of mathematical modelling. The analytical model for well inflow performance is developed. It successfully matches several field cases.
A New IOR Method for Mature Waterflooding Reservoirs: “Sweep Control Technology”
Authors: Wu Xingcai , Xiong Chunming , Han Dakuang , Liu He , Gao Shuling , Xu Hanbing , Dong Fan , Ren Fangxiang
Published: September 2014

For improving the recovery of water flooding heterogeneous oil fields, the classical conformance control method is to enlarge the swept volume as far as possible, usually by fine layering, profile control and water shutoff, and fracturing and acidizing, etc. However, with watercut rising, the remaining oil distributes in deep reservoirs, making the classical methods less effective. “Sweep Control Technology (SCT)”, a new IOR method, is put forward. The whole production-injection flowing field is taken as the studying target. The waterflooding effect impacting factors were classified into three levels: large-scale macroscopic heterogeneity, middle-scale mesoscopic heterogeneity and pore-scale microscopic heterogeneity. Based on the impact of the three levels of heterogeneity on sweep efficiency, we developed new corresponding SCT materials. For large-scale heterogeneity, we put the materials in accurate place to effectively inhibit water flow prevailing channels. For the middle and small scale heterogeneity, the water flow is diverted to achieve effective sweep control by means of effective material migration. So that we can realize complete adjustment and control of the whole flowing field to achieve efficient remaining oil displacement, and to improve the recovery of water flooding phase. The research and experiments in laboratory and field have proved the advancement of the method.
Identification and Modeling of Inter-Reservoir Cross-flow Using a Novel Material Balance Method
Authors: Montague E. T. , Airul Hafneh
Published: September 2014

A detailed material balance study of the Northern Area Deep reservoirs was conducted to address anomalous trends identified from p/Z analyses. The material balance study was conducted using a novel application of Petroleum Experts' MBal software, and determined that previously unrecognised volumes of gas were cross-flowing between reservoirs predominantly behind casing in the wells. The magnitude of the cross-flow volumes significantly impacted well and reservoir performance, but were unable to be modelled or quantified.

The approach that was adopted to model the inter-reservoir cross-flow using MBal as a “sub-surface abacus”, whereby injection of gas into the reservoirs was introduced manually to represent influx due to cross-flow. Additional production (on top of allocated produced volumes) was introduced to model the corresponding efflux of gas. Manually maintaining a volumetric balance between the efflux and influx profiles was difficult, but achievable, and provided an internally consistent method to model the complex dynamics of this reservoir system.

Detailed simulation studies have been recently conducted on the Northern Area Deep reservoirs and have complemented the findings from this material balance study. The MBal model has been updated regularly with over 6 years of additional production and pressure data, and the model is still holding a good history match. This has provided high confidence in the model's robustness, and validates the adopted methodology, which has broader applications to enable material balance modelling of “non-geological” inter-reservoir cross-flow.

The purpose of this article is to present the methods and practices employed in this process and to show how they can be applied to other fields/reservoirs.
Brownfield-Surface Network Debottlenecking and Mitigation Analysis: A Case Study
Authors: Haryanto E. , Thomson J. , Bolanos N. , Soendoro F. H.
Published: September 2014

When liquid production has levelled out despite continuing drilling and adding new wells into a production network, a surface network bottleneck issue may be suspected. The initial stage and cost-effective option in determining whether surface production was being restricted by excessive backpressure on the wellhead, or a certain part of the facility, can be done using surface network modeling. The result of surface network modelling itself is very often challenging due to minimal data availability and data uncertainties, or unclear characterization between a surface bottleneck issue and other problems such as artificial lifting and poor well performance. These challenges may be related to each other and often impede conclusions in determining any source of bottlenecks.

We discuss a case study and elaborate a detailed workflow to utilize a fully benchmarked surface network model with individual well models for bottleneck identification. Using the proposed workflow, production data analysis is performed prior to building the surface network model itself and eliminates confusion between production optimization related issues and any surface bottleneck. Benchmarking of the model and selection of appropriate flow correlations are used to provide a robust surface network model. Some pipelines or connections with potential bottleneck problems are successfully identified from the modelling that are later compared with field inspection to seek any potential bottlenecking evidence or indication. Based on high-level diagnosis, amongst many other possibilities, an emulsion-management challenge was suspected in the root-cause analysis, especially for gas-lifted wells. The study was completed with sensitivity analyses of different debottlenecking scenarios to further evaluate potential mitigation plan to maximize the brownfield's life and achieve the field's economics objective.
Successfully Improve Oil Recovery Using In-Situ Gas Lift and Gas Dump Flood at North Arthit Field, Gulf of Thailand
Authors: Rinadi M. , Dechanuwong V. , Harnboonzong P. , Lerlertpakdee P. , Rodpranee W. , Sriyanong P.
Published: September 2014

North Arthit field in Gulf of Thailand is a gas condensate field, but also has oil reservoirs that produce from number of wells. This paper explains the implementation of in-situ gas lift and gas dump flood technologies to increase production and improve recovery from a partially depleted oil reservoir in North Arthit field. A simulation study was performed to understand reservoir characteristic, drive mechanism and expected oil rate prior to the field implementation; the study results were to allow cross flow within the tubing to dump high-pressure gas from a deeper gas reservoir into the oil reservoir to increase reservoir pressure and sweep the oil to a nearby producer. This successful pilot work has opened up the opportunities for other small oil pools in Gulf of Thailand. A proper design of the in-situ gas lift and dump flood will significantly improve the oil recovery.
Linking Subsea Networks To LNG Plants: The Challenge Of Diurnal Swing
Authors: Sbriglia G. , Hester K. , Bonfanti R. , Castellitto T. , Negri E. , Montini M.
Published: September 2014

Numerical simulations have been performed on a gas field located 50 km off the coast in ultra deep waters. The production scenario combines field-to-shore multiphase production with onshore LNG processing facilities, which are based on gas turbines driving directly refrigeration compressors. One of the challenges to be faced in the design is the so called diurnal swing, which is the daily variation in requested LNG feed gas based on ambient conditions changes and hence LNG operating efficiency. Indeed, gas turbines available power is directly related to ambient conditions, like air temperature, pressure, etc; at the same time, it is recognized that the major effect is due to the air temperature. This work assesses the need to explicitly model the diurnal-swing effect and how it can affect the ability of the subsea system to meet gas deliverability requirements without adjusting the subsea wells choke on a half-day basis.

The system was modeled as steady-state, with average forecasted production rates, and also explicitly accounting for the daily flowrate variations. Transient simulations showed that the pressure built up and blew down very quickly in response to rate changes. These cyclical pressure variations must be managed by the subsea system and indeed affected well productivity. The higher backpressure did not allow some wellhead pressures to be drawn down sufficiently to meet requested gas rates, especially in late years when the field is more depleted. However, this shortfall was not realized in the steady-state modeling where the rate and pressure remains at a constant value. On the other hand, liquid content actually improved under transient diurnal-swing conditions compared to assuming an average daily rate. This was due to the periods of higher flowrate and higher pressure.

Overall, this study highlights for the first time that an explicit assessment of the diurnal-swing should be performed for such subsea systems along with the normal steady-state approach during all phases of the development.
Increasing Production Through an Innovative Analytical Approach in a Brown Field - A Case Study
Authors: Mandal Dipak , Bt. Ahmad W Zuraidah , Chaw Kit Teng , Bt. Hassan Siti Norhajar , Mansur Roslan
Published: September 2014

Early monetization of resources has become the key to have a competitive edge in our oil business today. In brownfields, this requires critical analysis of the existing performance, the sweep pattern, well drainage, and faster generation of robust cost effective redevelopment plan followed by rapid execution to get those early barrels. In Peninsular Malaysia BX is an oil rim reservoir with a large gas cap and moderate water drive. Oil production has declined rapidly in last few years with increasing GOR and water-cut. Existing models could not explain the current production behaviour. Apprehending building new models would take significant time, thus to arrest the unexpected decline in oil production, a classical reservoir engineering approach was adopted to identify bypassed oil and propose infill wells for additional production. With integration of production data, seismic, well logs and sand geometry, an innovative approach was used to find the less depleted areas. Well decline analysis, complemented by polygon balancing and normalised EUR bubbles at wells helped to identify locations where infill wells were proposed.

The team deliberated the subsurface and operation risks and assessed them as internal or external risks, prioritised them and built a mitigation plan. These fast track infill wells without dynamic model were very successful in increasing production and reserves, and provided high economic returns due to reduced costs and early oil. The field oil production increased by more than 80%.

This paper covers how the analytical approach with polygon balancing and normalised EUR bubbles was carried out to find the undrained areas. It also highlights challenges encountered during the planning and execution phases and the steps taken by the integrated team to overcome them. Encouraged by this success a number of this early monetisation projects were initiated which gave positive results thus proving the success of the technique.
A New Method of Gas Plateau Rate Optimisation: A Win-Win Solution for the Gas Field Operator and the Government as the Owner
Authors: Ariadji Tutuka , Kautsar M Telaga , Duha Dany Kurniawan
Published: September 2014

A gas field company concern is to seek the highest gas plateau rate as possible for a contract rate of sale gas to obtain the most economics field development scenario. On the other hand, the higher plateau rate causes more gas reserve left underground after end of the plateau rate for the rest of the life of a field, and this reserve left would be the government concern as the owner to maximize the field ultimate recovery. Having this fact, a new concept has been brought up to solve this optimization problem to find a meeting point between the two concerns by figuring the performance of the Recovery Factor (RF) at the end of the plateau rate or until the end of the contract; we name it Contractor Concern Recovery Factor (CCRF), and the performance of Remaining Recovery Factor (RFR) after the contract ends until the Field Ultimate Recovery Factor; we name it Government Concern Recovery factor (GCRF), with respect to Rate of Return (ROR), at which the two performances behave oppositely. We define this meeting point of CCRF and GCRF the optimum for both parties, a win-win solution for the gas field company as an operator and the government as the owner.

Having this optimization concept, a reservoir model of a real gas field is run for a sensitivity analysis study and Design of Experiment (DoE) of important parameters for the optimum gas plateau flow rate, and the results suggest that Original Gas in Place, is the most influencing parameter followed by average permeability and gas relative permeability. Finally, a correlation is introduced by applying the Least-Square method to find a relationship between the optimum gas plateau flow rate with the parameters, and the resulted correlation has an acceptable accuracy.
Applications and Lessons Learned During Integrated Subsurface Experimental Design ED Studies of a Giant NW Australia Gas Field
Authors: O'Reilly D. I. , Lightfoot T. J. , Das S. , Chung A.
Published: September 2014

In this multi-Tcf subsea gas development off the North West coast of Australia, reservoir simulation supports the key business decisions and processes. An important factor when providing production forecasts is ensuring that a range of possible outcomes (low-mid-high) are captured accurately by the models. The output from these models may then be used by decision makers for evaluating different developments and scenarios. The design of experiments (DoE) is commonly employed to aid the evaluation of subsurface uncertainties and characterise the impact and influence to key model outcomes supporting development decisions.

Field production performance is often driven by uncertainty in reservoir outcome. This paper is helpful to practitioners involved in any computer modelling of petroleum reservoirs who are interested in capturing the uncertainty inherent in a field and building an appropriate workflow for the development and sensitivity of a range of models. Both model building and using DoE to evaluate developments and Value of Information (VoI) studies for reservoir management will be shared. Integrated DoE focusing on static, dynamic and well-based uncertainties will be illustrated.

Results will cover:

– Lessons learned and best practices using ED (Experimental Design) to generate low-mid-high reservoir simulation models – Understanding reservoir and well based uncertainties separately – Evaluating incremental field developments using ED – Utilizing ED to anticipate range of surveillance responses

Few papers exist on the integrated application of ED to giant gas fields using reservoir simulation. Firstly, this case study will highlight some pitfalls to avoid during the workflow. Secondly, the authors will discuss the important issue of how to integrate or separate static, dynamic, well and facility based uncertainties. Thirdly, the work will show the unique application of ED in VoI and field development scoping.