bluuebunny/crossref_metadata_2025 huggingface dataset:
3D Petrophysical Modelling to Resolve Complex Reservoir Interpretation Problems: A Case Study from South East Asia
Authors: Aldred R. D. , Sritongthae W.
Published: October 2015

When using conventional petrophysical interpretation techniques on a clean sandstone reservoir in South-East Asia it was found that structure and heterogeneity in the formation caused the resistivity based Sw calculations to grossly underestimate hydrocarbons in place. The sands are layered and, although the porosity remains fairly constant, the permeability is highly variable with laminations of low-permeability water-bearing sands and high-permeability oil-bearing sands. The thickness of the layers is below the resolution of most log measurements.

This paper describes a technique for petrophysical interpretation of these reservoirs based on three-dimensional modelling of the formation properties. Extensive log and core data sets were available. Information from core was used to distinguish the different types of sand, NMR-T2 distributions were used to quantify the ratio of sand types at each depth and a saturation-height function was used to determine saturations for the different layers, based on height above the free water level. Synthetic log responses were created from the resulting models and inversion processing based on actual log responses was then applied.

Capillary pressure measurements showed that the low permeability sand layers had very high entry pressures, causing them to be water bearing through many intervals. The conventional resistivity logs were dominated by these thin water bearing layers, showing little effect of the presence of the oil in the high permeability layers. This is a similar effect to that commonly seen in laminated shaly sand reservoirs. UV fluorescence core photographs were found to be essential to the study as they clearly indicate the location of the oil and the oil water contacts in the cored intervals, even when the resistivity logs remain too low to differentiate the changes in fluids. This meant that the modelling could be verified in the cored intervals and then applied, based on the bi- and tri-modal T2 distributions, in the non-cored intervals. By modelling the formation properties at multiple scales, and taking formation anisotropy into account, the technique allowed good matches to actual log responses to be achieved and also provided good information for upscaling of the petrophysical properties to the reservoir model scale.

This case study illustrates a useful technique for situations where conventional deterministic and optimising routines don't give reliable results. It also provides a methodology, which can be built on in the future, to provide a more robust interpretation model for the many situations where formation structure and anisotropy affect log responses.
The High Temperature Effects on Pore Size Distribution of Tight Sandstone: An Application of Microwave Heating in Enhanced Gas Recovery (EGR)
Authors: Wang Hongcai , Rezaee Reza , Saeedi Ali
Published: October 2015

The present work studied the effects of microwave heating on sandstones with low porosity and permeability based on the comparison of pore size distribution (PSD) using Nuclear Magnetic Resonance (NMR) technique.

Microwave heating can heat the sandstone in a short time and cause physical and chemical change of rock and fluids inside. The heat evaporated water and changed the structure of minerals and pores so that the permeability increased which was measured from the Automated Permeameter. Before microwave heating, all samples are prepared into three different water saturations for NMR measurements: fully saturated using high pressured saturator, partially saturated using centrifuge and dry using conventional lab oven. Then the T2 distributions were measured in three different conditions. Samples were prepared and measured in the same way after heating.

It is found that Scanning Electron Magnetic (SEM), which can be used to compare the structure changes with high-resolution images, was used to support the NMR measurement; while Medical CT played a similar role by imaging full sample with lower resolution. Together they can give an interpretation of the T2 distribution or the pore size distribution.

The permeability increased after heating and the T2 distribution of each sample has changed. Minerals have been changed due to water evaporation and high temperature. It accounts for the change of T2 distribution. Comparing plots and images before and after heating, the heating effects are obviously positive to EGR.

We have had a good understanding of the effects of high temperature on permeability by studying the change of pore size distribution with NMR before and after heating. With the support of SEM and Medical CT, we got visualized evidence for our interpretation of the change of pore size distribution.
Kickoff Plug Best Practices for Shallow Wells in Awali Field, Bahrain
Authors: Hanna Rusty , AlGhani Sayed , Abreu Miguel De , Pohl Jonathan , Al-Hawaj Husain , Rosero Ivan
Published: October 2015

Setting cement plugs for sidetrack operations is a critical, challenging, and time-consuming operation. In many cases, a successful sidetrack operation requires several cement plug attempts or lengthy drilling operations, resulting in increased operation cost. In the past, when required to sidetrack a well, cement kickoff plugs were regularly tagged without having achieved the desired compressive strength, with added risk of stuck pipe in soft cement and increased wait-on-cement (WOC) time. The poor cement plugs usually resulted in a time drilling operation after additional WOC time. Placing a successful kickoff-plug (KOP) consistently on the first attempt is required for a cost-effective sidetrack operation, which, by itself, is considered an additional cost to any drilling project. In the Awali field in Bahrain, drilling operations faced the challenge of increased loss time in KOP operations. Operator wanted to reduce WOC time by improving the performance of the cement KOPs. The target was to complete the sidetrack operation in well depths less than 3,000 ft and static temperatures of about 140°F within 8 to 12 hr, after the cement plug has been placed.

A thorough analysis of previous design and execution cement practices was performed to identify the actions needed to optimize the previous performance of cement plugs. Advanced cement plug optimization software was used to support the evaluation of the risks associated with the placement of the slurry. Data from extensive laboratory testing of several cement slurry systems were used to evaluate the effect of the slurry properties on optimizing the system deemed most suitable for this application. The studies also included a detailed review of the industry best practices that are applicable to the conditions of the field. The results of the implemented best practices for the design and execution of KOPs in shallow wells in the field under study demonstrated an improvement of the success rate to 100% and better cement plug performance, contributing significantly to minimizing the time and cost of performing sidetrack operations.
Efficient Application of Large-Bore HEWD in Total Mud Loss Environment Saves Two Days Rig-Time, Offshore Mexico
Authors: Ayala Enrique , Banuet Siddhartha , Murillo Ricardo , Karrer Cesar , Arnaud Alex , Riquezes Cruz , Campos Nestor
Published: October 2015

In 2013 the operator initiated a horizontal drilling campaign to increase oil production in Sihil field, offshore Mexico. The new well plan required 14½×17½ and 12¼×14½ Hole Enlargement While Drilling (HEWD) in top hole sections. The challenges were different compared to other top hole applications in the area and include hard formation drilling with low density WBM in a total lost circulation environment (no surface returns). The BHA (bottom hole assembly) would be required to penetrate fractured limestone, shale and dolomite with UCS from 15,000 to 30,000 psi. During the planning phase, engineers realized that neither the 14½×17½ or 12¼×14 ½ HEWD sections had been attempted in a total loss situation in the region.

Solving the issues would require accurate BHA modeling and a unique hydraulics system that would effectively clean the hole, provide the necessary pressure drop required to efficiently dive the RSS (rotary steerable system), allow MWD demodulation and enable optimal hydraulic reamer operation. The drillstring would have to be dynamically stable for good directional control despite rollercone TCI pilot bit (IADC517) and 13mm PDC reamer cutters.

The first two wells drilled under these conditions experienced reamer nozzle erosion. To temporarily solve the problem three reamer nozzles were blank-out. While this did produce an immediate solution it forced rig personnel to activate the reamer at the surface leading to a dedicated trip for drilling out. Blanking out the nozzles also reduced reamer life by reducing lubrication on the cutter blocks.

Having evaluated root causes for all washout cases, a change to extended nozzles was proposed to reduce erosion on the retainer and the area adjacent the nozzle bore. Hardfacing material was added to the nozzle retainers to increase durability. The new nozzle configuration was modeled and compared to the old nozzle design. The results of CFD (computational fluid dynamics) analysis suggested the change would yield positive results.

The extended nozzle design was tested on Well-3X and Well-4X and reduced erosion on the nozzle retainer and adjacent area. Cutter block cleaning was improved while eliminating the dedicated drillout trip (48-hours rig-time). Hydraulics were properly adjusted to deliver the required pressure-drop to efficiently operate the RSS/reamer and obtain the optimum choke size for signal demodulation in total mud losses. The operating parameters outlined by the modeling system produced dynamically stable drilling while mitigating S&V during transition events and RPM/WOB.
Sustainable Zonal Isolation under Extreme High Temperature Conditions
Authors: Shadravan Arash , Shine Joe
Published: October 2015

Well integrity has an utmost importance for upstream operations that has resulted in many studies to improve zonal isolation. Few papers comprehensively investigated the elements involved in cementing service delivery that are conducive to both well integrity and zonal isolation for extreme high temperature conditions. Geothermal, High Temperature and High Pressure, Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS) (also known as Steam Flood) and Fire Flooding are all examples where the cement sheath can experience extreme high temperatures.

This study emphasizes on sustainable zonal isolation throughout the life of wells facing extreme high temperatures. The purpose of this paper is to present the challenges of extreme high temperature cementing and show solutions used to assure cement integrity under such extreme environments. These challenges were reviewed and the most up to date solutions were discussed. The examples explained through this paper demonstrate the role of these critical elements for safe and environmentally friendly extreme high temperature well cementing. This analysis provides recommendations to sustain long-term zonal isolation when operations involve with extreme high temperature conditions.
Thinly Bedded Reservoir Study, Application of Sand-Slit-Clay (SSC)-SHARP-Thomas Stieber Juhasz Models, in a Deep Water Field, Offshore Sabah, Malaysia
Authors: Kantaatmadja Budi P. , Rashid Syamsina Bt. , Nurhono Achmad A. , Masoudi Rahim , Neville Tom , Taesoo Kim , Basu Debnath
Published: October 2015

Thinly bedded reservoir study in the deep-water area, offshore Sabah, Malaysia, was performed with the primary objective of improving the understanding of its complex geology. The nature of reservoirs, which are predominantly thin-bed and laminated sandstones of submarine fan environment, contain a high level of uncertainty in its lateral continuity.

Standard shaly-sand log analysis methods contribute pessimistic values of porosity and water saturation when applied to these reservoirs. Few techniques are then presented for the determination of these rock properties, which are more reliable with core and production data.

Core grain-size analysis of these reservoirs shows that clay content is generally low but the silt content can be significant. Furthermore, log responses show that porosity distribution and mineral-conductivity are influenced mainly by the silt-size particles.

A sand-silt-clay (SSC) model was then developed from density-neutron crossplot, which model is also used to determine porosity and water-saturation in addition to volumes of lithology components of the reservoirs.

Furthermore, other petrophysical technique, called SHARP, uses 1D convolution filters to match thin bed modelled log curves to their corresponding measured responses. A petrophysical evaluation using standard resolution logs and the thin bed resistivity (SRES) from image response are used to develop a thin bed model that yields high resolution logs.

For zones where the resistivity image indicates significant thin bed development, the standard petrophysical analysis should also indicate the existence of free fluid. Although the porosity tools cannot resolve the thin beds, they nevertheless represent the bulk volumetric over the interval, known as Thomas-Stieber-Juhasz (TSJ) method, and would be able to differentiate between porous zones with lower clay volume versus porous shales with high clay volumes. The main point is that if a thin bed interval has some calculated free fluid volume using standard resolution logs, then a thin bed analysis is warranted.
Early Assessment of Environmental and Social Risks and Impacts of a Shale Gas Development in Morocco
Authors: Barcelo Ignacio
Published: October 2015

An operator has been granted a reconnaissance permit for the Hauts Plateaux and the Boudenib Blocks in Morocco, and is exploring the feasibility of an eventual Shale Gas Development Project in these areas. Given the particularities of shale gas developments, and applying the principle of early identification of risks, a series of studies have been conducted for the early assessment of environmental and social risks and impacts that such a project could have.

Studies performed for identifying critical issues compromising the feasibility of the project were: Hydrogeological Studies, Environmental and Social Baseline Studies, Permitting Roadmap, and Conceptual Environmental, Social and Health Impact Assessment.

The Hauts Plateaux and Boudenib Blocks show a small population density and large uninhabited areas, they are amongst the poorest regions in Morocco. There is a general lack of surface water resources, but groundwater resources were found to have the potential to ensure the water supply for a shale gas development. The Blocks present sensitive areas, including a Biosphere Reserve and Ramsar sites. A typical shale gas development assumption was considered for identifying and preliminary assessing potential risks and impacts. The most critical issues identified included threats to existing fragile ecosystems, the potential impacts on groundwater resources quality and availability, the loss of livelihoods and potential need of resettlement of local communities, impacts on cultural traditions and community cohesion, or conflicts between the establishment of a new industry and the development priorities that are currently being considered by the relevant administrations for these areas.

The studies performed conclude that a Shale Gas Development in Morocco could potentially be feasible in terms of availability of resources, permitting, and potential impacts. The studies also identify a set of existing environmental and social constraints that would likely impact the development of the project, and that would have to be considered for managing the project's risks.
Setting New Records for Drilling the World's Longest Horizontal Well in Basement
Authors: Miguel D. L. , Anh P. L. , Wittry A. , Vernizeau B. , Duy C. , Malpas P.
Published: October 2015

Although worldwide drilling focus is primarily on sand and shale for oil production, a few operators rely heavily on tapping reservoirs basement or volcanic rock reservoirs. In Vietnam, drilling oil and gas in these formations has played a large role in the country's oil and gas activity. The development of technologies might not have reached its peak, but the operating strategies have been continuously tailored to improve the authority for expenditure (AFE) savings.

It has never been proven that drilling a long horizontal >3000-m well section in basement could be efficient and economic. Cost and risks related to the challenges of drilling could easily increase as the basement section lengthens. These challenges include slow drilling time in basement section, numerous bit runs and significant tripping time, high vibration combined with very abrasive formation that quickly causes the bottomhole assembly (BHA) to deteriorate, high applied weight on bit for faster rate of penetration risks the buckling of drillpipes, drilling through massive losses with excessive consumption of brine mud and additives, highly corrosive mud system that affects all steel in the BHA, unpredictable cuttings deposits in the wellbore during losses, lack of available downhole tools to drill the long basement interval, and quick changes of borehole temperature from high temperature to low temperature.

Extensive well planning has always been the key to operational success. The detailed engineering design process involves using an advanced drilling simulation software that comprehends the boundaries/limitations of the surface and downhole equipment. The simulation sets a workable plan to achieve the project objectives safely and efficiently.

Additionally, the basement reservoir's success criteria highly depend on the well passing through productive fracture zones. In the difficult basement conditions in Vietnam, advanced logging-while-drilling (LWD) technology was utilized to accurately detect productive fracture zones, and it helped in optimizing the well completion design. The ability to see and measure the open fractures has aided in the development of better defined and optimized production strategies.

The collaboration of all these aspects has resulted in the drilling of the world's longest horizontal well in basement rocks with proven cost savings for the development of the small and untapped reserves.
Cluster Spacing Optimization Based on a Multi-Fracture Simultaneous Propagation Model
Authors: Lu Qianli , Guo Jianchun , Zhu Haiyan , Zhao Xing
Published: October 2015

Multi-cluster staged fracturing is an effective method to exploit shale gas. Field observations reported some clusters did not generate fractures. X formation in Sichuan Basin is a 3000m deep shale reservoir. The horizontal stress ratio (Shmax/Shmin) is around 1.4 which is therefore difficult to generate fracture network. How to enable all fractures propagate effectively from each cluster and generate enough stress interference to enable fracture network is of critical concern.

This paper established a 2D fracture propagation model based on finite-element method to simulate multi-cluster fracturing. The fracture propagation model couples seepage-stress-damage theories to simulate fracture propagation. The cohesive element is used to simulate the forming of fracture, and the filtration from fracture to matrix is taken into consideration. This model is used to study three fractures propagating simultaneously from three clusters. Different cluster spacing cases were simulated to investigate the fracture geometry and the stress field.

When the cluster spacing is 10m, 20m and 30m, the simulation shows that the length of the middle fracture is severely restricted; but for the side fractures, the length is over propagated. When the cluster spacing is 40m and 50m, balanced propagation of all the three fractures is achieved. In 10m, 20m and 30m cases, the stress field shows that in front of the middle fracture, there is a high compressive stress area caused by over propagated side fractures, and this stress could prevent the middle fracture from propagating. So the range of optimized cluster spacing is reduced to greater than 40m. In order to increase the possibility of generating fracture network, the cluster spacing should be small to create high rock frame stress between the fractures. By considering the fracture geometry and stress field, the optimized cluster spacing is 40m cluster.

This paper presented a method to optimize the cluster spacing by both considering the fracture geometry and stress field. Cluster spacing optimized by this method could enable the effective propagation of all main fractures and increase the possibility of generating fracture network.
Field Development Challenge of Combination Traps in JDA Area of North Malay Basin
Authors: Setiawan A. S. , Rachmadi A. , Simatupang M. H. , Jiraratchwaro C. , Mohd Pushiri M. F.
Published: October 2015

To develop a field with combination structural and stratigraphic trap style is always challenging, especially with trap uncertainties that are coupled with limited exploration and appraisal wells. The potential production shortfall or non cost effective development plan would be an issue if the number and locations of the wells are not carefully selected. Thus, a comprehensive reservoir modeling study, both static and dynamic modeling was designed and instituted to integrate all available information and geological concept.

In the Muda South Central (MSC), which will be discussed further in this paper, structural re-mapping was conducted to refine the trap and structural style. However, the plunging nose structural styles do not have a closing contour to the north of the field, which requires interpretive arbitrary boundary to isolate the compartment and to limit the field boundary. The nearby field in the northern part has a four way dip closure which proves to have a different fluid system with the studied area. Concurrently, a geological facies modeling study was generated using regional trend knowledge and guided by seismic attribute qualitatively. Reservoir trend direction has played an important role in hydrocarbon trapping. The high uncertainty of reservoir presence was assessed by including inputs of low and high extremes sand-shale-ratio in facies modeling exercise for the purpose of capturing reservoir uncertainty.

In dynamic simulation, Simulation Opportunity Index weighted with Gas Initially In Place (GIIP) map is considered to identify sweet spot location. This enables the subsurface team to optimize the number of development well and the placement of the well at the ‘sweet spot's location. Water and sand production prediction is taken into the consideration to minimize the impact to well performance.

Subsurface uncertainty analyses were performed which includes sand distribution, fluid contact in vertical and lateral extension, rock & fluid properties, aquifer strength and well performance. The uncertainty of the number of development wells was anticipated by performing multiple simulations for low and high case. The model is intended to be used as a guidance to subsurface team for decision making during the development drilling campaign.
Inherent Safety Against Cyber Attack for Process Facilities
Authors: McGlone James
Published: October 2015

Process plants, including oil and gas production facilities, need to be protected against physical consequences generated from cyber-attack. While a lot of effort has been placed on securing the computer systems themselves, the design of the facility is often ignored, but is the most important component of the defense against cyber-attack. It is possible to build plants that are inherently safe against cyber-attack by designing in systems and safeguards - such as relief valves and current overload relays - that are not vulnerable to this threat vector.

This paper will review the most common methods for process hazards analysis (PHA) of process industry plants, and then supplement those methods with a "cyber review". The purpose of the cyber review is to determine if there are any cyber-attack vectors that can cause significant physical damage to the facility, and if so, make recommendations for modifying one or more of the safeguards in a cyber-vulnerable vector so that they are not vulnerable to cyber-attack.

The approach that will be discussed includes analysis of the causes of safety incidents, the safeguards that prevent the causes from resulting in consequences, and the magnitude of the consequences that might result from the realization of these hazards. The discussion will include a case study from the oil and gas industry where a Hazards and Operability (HAZOP) study was assessed using a PHA cyber review in order to determine whether or not the facility was inherently cyber-safe, and if not, make recommendations for design modifications that would make the facility cyber-safe.
Feasibility Study of Smart Completion Application in a Complex Mature Field (Dunbar, North Sea)
Authors: Wulandari Tamara , Mazzucchelli Davide , Rasoanaivo Ombana , Zaugg Eric , Olivier Gosselin
Published: October 2015

The Dunbar field is characterized by a high degree of geophysical, geological, and dynamic complexity. Current field recovery factor is 30 %, after 20 years of production. The field is compartmentalised by a number of faults, which subdivide the field into four main areas: the West Flank North, West Flank South, Frontal Central, and Frontal South, with limited to no communication between panels. Permeability degradation with depth is observed in all West Flank and Frontal panel layers, with significant impairment due to alteration of clay morphology, below paleo oil water contact, with a permeability range of only 1-10 mD. Half of Dunbar field's accumulation is located in this poor permeability region, explaining the limited recovery factor. New production technology application is necessary to help improving recovery from this low permeability region.

Passive inflow-control devices (ICDs) and active inflow control valves (ICVs) provide a range of fluid-flow control options that can enhance the reservoir sweep efficiency and increase reserves. Both ICVs and ICDs are capable of equalizing the inflow or outflow into heterogeneous reservoirs. With a more evenly distributed flow profile, one can reduce water or gas coning, and solve other drawdown-related production problems, thus improving the field recovery.

The objective of this study is to evaluate the interest of ICD and ICV application for the coming phase IV drilling campaign. Phase IV infill wells will encounter reservoirs with different levels of depletion and sweep efficiency. Early water breakthrough may become a threat to the success of the campaign. Application of smart completion on a new injector may help optimizing the final recovery on the West Flank panel, intelligent completion providing the availability to selectively steer water injection into zones where it is most needed at a particular time.

First, the phase IV wells are analysed to choose the best candidate for smart completion application leading to retain one horizontal producer and one horizontal injector in West Flank panel The study was performed using a history matched ECLIPSE 300 ® reservoir model of West Flank panel.

The study shows that the installation of ICD or ICV improves the well recovery factor by 10 to 15% and the overall field recovery factor by 1%. The simulation results show that smart completion application in the injector well improves the recovery from poor permeability region by 11 %. An important aspect of the work reported in this paper is also to test the proposed smart completion strategy against uncertainties on reservoir properties. Simulation results show that smart completion is more flexible facing different geological uncertainties.
The US Unconventional Gas Experience - Can the Model be Repeated in Other Countries?
Authors: Chandra V.
Published: October 2015

The US has experienced massive increases in reserves and production of natural gas from unconventional reservoirs. The scale of this increase is unprecedented and is the envy of the rest of the world. Largely as a result of general regional studies by the US Energy Information Agency (EIA) and others similar organizations which promise similar, and in some cases, even higher resource volumes than in the US, many other countries have embarked on unconventional gas exploration efforts.

This presentation will describe the impact of US shale gas and the success factors responsible for its growth. These factors include ‘below ground’ factors such as favourable geologic conditions, presence of natural gas liquids and abundance of well and reservoir data. These factors are, in varying degrees, present in other countries and regions as well.

However, the US also enjoys a number of unique ‘above ground’ factors such as a dynamic service sector, low cost operators, favourable tax and regulatory regime, easy access to pipeline capacity, availability of capital and technology, transparent gas prices, and property rights to land owners. These factors are much harder to find in other countries and regions and are more crucial, it can be argued, for development of unconventional gas than for conventional gas.

Thus, the answer to the question "Can the US model for unconventional gas development be repeated elsewhere?" is unfortunately, "NO". Unless governments and regulatory agencies take strong steps to improve their ‘above ground’ score, it is unlikely that these countries will enjoy the success of unconventional gas development to the same extent as the US.
Innovative Borehole Treatment Utilising Inflatable Packer Straddle System Technology
Authors: Loginov Arthur
Published: October 2015

Open hole fracturing and acid stimulation utilizing the traditional cemented liner and hydro jet perforations or mechanical packers with ball activated frac sleeves have been deployed successfully in the Unites States and Canada for years. One of the primary concerns about the conventional liner methods is assurance of knowing where the fracture or acid is placed. There is no way to determine if there was adequate annular isolation to ensure the planned treatments were placed in the zone of interest.

In an effort to effectively place the fracture in a known location, an inflatable packer straddle system was introduced and utilized to treat the Bakken, Midale, Spearfish and Torquary formations in the southeast Saskatchewan region of Canada. Knowing the location of the fracture provides clarity to understanding the production results. Producing as a barefoot completion may also add incremental production from naturally fractured intervals that may not be exposed to newly-created fractures and also provides flexibility for later interventions or adding laterals.

Improving the procedure, a setting head was developed to drastically reduce time spent between stages reducing water consumption by eliminating the need to drop and displace setting balls to activate the inflatable system at each setting interval. Using this system, the operator can monitor annular pressure in real time to understand when the fracture is starting to break around the upper packer allowing the operator to make adjustments to the fracture treatment of subsequent zones during the job.

This paper will address main considerations of tool operation, case histories highlighting job procedures and lessons learned after several jobs. It will also address use of the straddle system for entering existing wells to re-fracture the formations to improve production and extend the life of the well.
Risk Analysis Significantly Reduces Drilling Project Costs: Vital in the New Oil Price Era
Authors: Gibson M. , Pawlewski M.
Published: October 2015

This paper portrays how drilling project costs can be reduced significantly, through the use of Risk Impact Amalysis, which is vital in the current era of unprecedently low oil prices which puts pressure on the whole chain of oil and gas services.

New ways of thinking and inventiveness are required if we are to keep drilling as opposed to stacking rigs which is happening at an alarming rate particularly on land in the U.S.A. If the cost of drilling cannot be reduced further, rigs will be stacked, several "cold" and the lucky ones "warm’.

This paper desrbibes how, through focused risk anaylsis, a 10,000 rated rig was allowed by the authoriesto drill as opposed to the more normally required 15,000 psi requirement.
A Cable-Controlled Separate-Layer Production Technology
Authors: Yuning Wang , Xin Wang , Meng Cai , Renyong Liu , Qingfeng Yue , Qinghai Yang
Published: October 2015

In high water cut oilfield, the separate-layer producers often face the problems of low separate-layer control level, difficult water locating and plugging, high operation cost and low testing and adjusting efficiency. As to solve these problems, new separate-layer production technology is required. The paper proposes a cable-controlled separate-layer production technology. The cable-controlled separate-layer production system consists of adjustable production regulator, testing and adjusting instrument, ground controller, and some matching tools. In the operation process, the testing and adjusting instrument is run into the wellbore through cable. The locator of the instrument can fix the accurate position where the target regulator is. After the delivery of the instrument, the testing and adjusting instrument connects with the adjustable production regulator. The liquid flow rate of the regulator can be adjusted continuously according to the instructions and the flow rate can be read simultaneously on the ground. The pressure and water cut of the single layer can also be monitored. Once the testing and adjusting of the target regulator are accomplished, the instrument disconnects with the regulator and move on to the next layer under the command from the ground. Field tests showed that the technology realized production adjusting and parameter testing of each layer in the producers. This technology requires the producers to possess well-preserved casing tube and annular testing condition. The technology is applicable to the rod pumped wells with big water cut variation, and the important wells whose reservoir need to be specially monitored. Because the testing and adjusting instrument is run into wellbore through annulus, the operation can be implemented while the pump unit is working, without interfering normal production. The cable-controlled separate-layer production technology effectively relieves the planar, inter layer and interior layer production contradictions. The balanced production of all kinds of reservoirs is realized and the producing capacity of medium-low permeability reservoirs is released, improving production rate and oil recovery.
Failure to Success to Hydraulically-Fracture-Stimulate a Low Permeability Oil Sand in Sumatra, Indonesia
Authors: W Faizal Ardi , Maryono Dedi , Prakoso Ambaria , Hezmela Rizka , Tsangueu Barbara
Published: October 2015

DC-15 is one of 17 oil production wells in the Kuat oil field in the Malacca Strait PSC, Sumatra, Indonesia. The reservoir is in the Lower Pematang Sandstone (6699 – 7015 ft.), which is a massive sandstone 281 ft. thick, with porosity of 11-14%, permeability of 2-10 mD, and water saturation above the 100 ft. transition zone of 20-30%

The reservoir is normally-pressured at 2200 psi, but has a high temperature gradient of 5.2 degF/110 ft., so the reservoir temperature can reach 325 degF

This paper tells the story of fraccing the DC-15 oil development well, which transformed the well from commercial failure in 2009 to commercial success in 2013, and covers perforation strategy, fluid recipes, proppant selection and frac operations. Improved frac design by applying lessons from the first frac job led to successful placement of the frac. The frac managed to increase the oil rate from 38 bopd to 168 bopd and increase the expected oil recovery from 53 mstb to 147 mstb, turning a likely money-losing well into a confirmed money-making well.The main changes were: Changing the perforation density from 5 spf to 12 spf helped to reduce the friction pressure during treatment allowing the frac to be placed at higher rate with lower surface pressure and reduced risk of screen out.Changing the frac fluid from conventional polymer fluid with zirconate-crosslinked fluid to the newly improved high temperature fluid that allows 5 lb./1000gal less polymer and has lower friction pressure hence the pump rate could be increased from 13 BPM to 20 BPM;Changing the proppant from 12/18 and 20/40 Intermediate Strength Proppant (ISP) to 16/30 High Strength Proppant (HSP) mitigated against crushed proppant production, which allowed the well to be produced at its full capacity.Adding fiber based proppant flowback control agent in the last proppant stage was successful to avoid proppant flowback.
Unconventional Radioactive Source Retrieval Inside LWD in Horizontal Well
Authors: Permana A. Aziz , Pramukti Cahya Dadiyanto , Wahyudi Danar Aji , Reza Rama Aditya , Moehidin Moehidin , Setiawan Adjie
Published: October 2015

Horizontal drilling is one of development strategies to optimize the oil recovery, especially in a mature field. Horizontal well can reduce water and gas coning and prevent the pressure drop around the well bore, therefore the oil recovery can be increased.

Radioactive source in Logging While Drilling (LWD) tools is used for X-42 horizontal drilling well but stuck problem that occurs during the drilling operation can be caused by differential sticking or failure hole cleaning. High angle inclination in horizontal well certainly increases the difficulty of retrieval job.

As a company regulation, the radioactive source should be retrieved before continuing the efforts to free the drill string. The wireline has agreed to help the radioactive retrieval but this operation should be done in 81° of inclination. Then, it will need a thrusting force to facilitate the bottomward movement of the assembly. Two attempts of retrieval with wireline are made before they bring up the idea of using sucker rod as the replacement a wireline cable.

This paper explains how the unconventional radioactive retrieval method with sucker rod as the alternative of wireline is more reliable to retrieve the radioactive fish especially in horizontal wellbore which technically has a very high inclination and 3D profile which the tool need a thrusting force to push the fishing tool assembly to the bottom.
Investigation on the Suitability of Virtual Flow Metering System as an Alternative to the Conventional Physical Flow Meter
Authors: Varyan R. , Haug R. K. , Fonnes D. G.
Published: October 2015

The interest in Virtual Flow Metering (VFM) has been increasing as awareness of its capabilities and benefits as an alternative or backup to the conventional physical flow meters evolves. Despite the fact that the technology has been in operation for more than 20 years, the adoption of this metering technology remains slow, particularly in Asia Pacific region. Virtual flow metering system provides real-time production monitoring of wells. A fine-tuned model and sufficient well instrumentation can also detect water breakthrough in the gas production well or gas coning in an oil producer. The main objective of this paper is to improve the general understanding of virtual flow metering technology and provide a basis to evaluate if implementation of VFM is a suitable alternative to conventional physical flow metering for a given system.

The VFM technology is based on an online (real-time) steady state multiphase flow simulator (thermo-hydraulic models) of the field, where flowrates are estimated using a powerful multivariable optimization solver. For individual wells, the model typically includes the production system from reservoir up to commingling point, e.g. manifold. Successful utilization of virtual flow metering technology is dependent on the availability and accuracy of instrumentation. Model tuning also plays a critical role in a VFM system as it is required to compensate for changes in the system and fluid characteristics throughout the life of field. This paper exemplifies a case study to show how the accuracy of VFM might change over time and the importance of performing model tuning regularly.
Strategic Handling of Stranded/ Associated Gas During Oil and Gas Exploration - A Case Study on a South East Asia Field Model
Authors: Sankararaj Rubakumar , Mirzaee Farnoosh , Wadsley Andrew
Published: October 2015

This paper presents a complete integrated asset model for gas planning and, in particular, the handling of stranded gas during exploration. Uniquely, it models a gas network from the reservoir, right through to product allocation based on contractual obligations. It back-allocates through the network from the market, to ensure accurate supply and product tracking. We show how this type of model provides unprecedented confidence in field evaluation and gas planning.

The market-based approach to integrated asset modelling that we used includes an optimal amount of information to deliver a fast, accurate solution. Oil and gas exploration activities do not usually involve planning for stranded or associated gas. Many discovered gas reservoirs are left undeveloped due to a lack of scenario analysis during the exploration phase. A fully integrated gas planning approach is required for effective field development planning in a timely manner. This has been a subject of intense research and development in recent years. Stranded gas reserves can be effectively developed using proactive market planning and strategic gas exploration guided by an integrated gas planning approach. As such, our model includes reservoirs, platforms, facilities, pipelines and markets to effectively understand the network deliverability.

In this paper we defined multiple scenarios for bringing up gas from reservoirs, through the facilities and delivery point, right up to allocation of resources to meet the market demand. The case study deals with a market-based approach for modeling 40 gas reservoirs and associated gas products from nearby platforms. The practical constraints such as condensate handling capacities, compressor systems, and contract gas quality are integrated into the model analysis.

The unique, fully integrated reservoir to market approach to IAM we demonstrate in this study provides a real breakthrough in E&P companies’' ability to model and run scenarios against their complete gas network in a relatively very short time. In particular the back-allocation from the market provides confidence around their ability to meet their contractual sales obligations and enables product tracking through the whole network.
New Multilayer Boundary Detection Service Employing in Complex and Mature Reservoir of Bohai Bay, Northern China
Authors: Guo Xija , Jia Yong , Fan Kai , Yang Liuhe , Zhao Guoquan , Wu Kai , Wang Fei , Li Cang , Gao Zhujun
Published: October 2015

Bohai Bay basin, the largest offshore basin of China, is located in northern China. Its oil and gas resources are commercially operated by China National Offshore Oil Corporation (CNOOC) since 1967. From 1967 to the present, more than 100 production platforms have been put into operation in a 43,000-km2 exploration area, including both development projects on the greenfield and infill projects on the brownfield.

The predominant depositional environment of Bohai Bay basin is a shallow delta and a meandering river system complicated by faults, which leads to fully developed interbed interference and high geological uncertainty while drilling horizontal wells within the greenfield. For the infill projects, high water cut is the primary concern, especially after long-term development. Therefore, our trajectory must be controlled precisely in a desired position to overcome the existing or potential water issue. As a solution to these challenges, a new multilayer boundary detection service has been introduced to CNOOC for the first time.

Outstanding outcomes have been observed by implementing this new multilayer boundary detection service. This innovative technology was applied to two challenging wells, well A of a development project achieved 377m measured depth (MD) lateral exposure with 100% net-to-gross (NTG) while depicting whole individual sand bodies and their mutual lateral contact relationship clearly, which not only can optimize the final NTG but also supply much detail, allowing for a more robust reservoir characterization. By using this technology on both landing and lateral section drilling for Well B of the infill project, target top was identified 3m true vertical depth (TVD) in advance and landed less than 1m below the target top with very low incident angle. Precise landing and lateral placement of horizontal wells and the use of inflow control devices for completion, have become critical to the success of this campaign. The results have shown that water cut has significantly declined from an average of 46.2% to 2.1%. This considerable decline can can bring higher recovery rate to this brownfield.

Even for the entire China market, this was the first time that the new multilayer boundary detection service was introduced. This paper illustrates an exemplary case study of using this innovative technology for a better understanding of reservoir characterization and higher recovery rate while performing high quality geosteering in complex and mature reservoirs.
Experience and Lessons Learned to Increase Job Success Rates for Hydraulic Fracturing in the High-Temperature Lower Pematang Sandstone Formation
Authors: Rahayu Sri , Subiantoro Edy , Hafizh Gama
Published: October 2015

The Lower Pematang Formation is a high-temperature sandstone reservoir (up to 350 degF) in the Central Sumatra Basin in Indonesia. It is a low-permeability reservoir (0.5 to 3 mD), and so oil flow rates are often sub-commercial, despite high initial reservoir pressure and gas-lift.

The obvious method to improve oil rates and recoveries in this reservoir is hydraulic fracturing.

The 1st campaign of Hydraulic fracturing was conducted in 2008 (2 wells), the 2nd campaign in 2009 (3 wells), the 3rd campaign in 2011 (2 wells) and the latest campaign was in 2014 (3 wells).

During the Frac Jobs, the team experienced operational problems due to high bottom-hole temperatures of 320 degF at 7000 ft. depth.

When pumping frac fluid at higher rates, the frac-packer released and jumped up because of thermal shrinkage of the frac string. It happened in the first campaign in MSDC-08, and again in the 2nd campaign in MSDC-10, where the pressure surge also burst the casing.

After the first packer release, the frac string was redesigned to include a 10 ft. expansion joint. Yet the second packer failure still occurred. After considering a safety factor, the team added a second 10 ft. expansion joint to overcome worst-case elongation and shrinkage effects. In addition, the team kept the annulus pressure at 500 psi to maintain downward force on the packer.

Another well integrity problem caused by high bottom-hole temperature was out-of-shape casing, whereby the production packer or cement squeeze packer could not be set at the desired depth. So, casing selection is very important to support future frac jobs.

Pre-frac CBL and Caliper logs also are important to identify poor cement bonds and out-of-shape casing, as frac job success needs cement isolation and a smooth casing face.

Once these elements were all achieved, the frac-job success rate approached 100%.

This paper will take the reader through a journey of frac failures, design changes, more failures and then finally on the road to success.