bluuebunny/crossref_metadata_2025 huggingface dataset:
Discovering New Hydrocarbon Pay Sand Beyond The Wellbore With Reservoir Mapping While Drilling Tool – A Case Study From Offshore Sabah, Malaysia
Authors: Kyi Ko Ko , Latiff Nazri Abdul , Yen Kok Kwi , Saadon Danial , Rahim M Ikhlas , Jaafar Juhaidi , Afandi Tomi , Fei Ng Kiang
Published: October 2016

Tango Field, located offshore Sabah in East Malaysia, is a mature field which has been producing oil and gas for more than forty years. This field has many fault blocks, thus creating barriers to fluid and pressure communication between different fault blocks. Furthermore, the reservoir sands are turbidite sands which are difficult to correlate across the whole field. Being fan lobes, it is not easy to target these sands in drilling development wells. As part of the campaign to improve recovery and sustain production, two infill wells were drilled during 2014, by sidetracking two existing wells from the Tango-B Platform, which is located in the western part of the field. The target reservoirs are M1 and M2 sands, which still carry some upside potential based on the latest review of the field performance. To properly target and penetrate these sands in the planned wells, the Reservoir Mapping While Drilling LWD (DDEM) tool, in combination with standard triple combo LWD (Logging While Drilling) tools, was deployed. This is to ensure that the well trajectory stays within the targeted sands and the bed boundaries are detected long before the drill bit exits the sand body. Unlike previous deep reading LWD resistivity tools, the DDEM tool is a Deep Directional Electromagnetic Propagation tool which has the capability to see about 30 meters laterally beyond the wellbore. While drilling the first well, the target sands were penetrated as planned. However, there was a pleasant surprise where a new hydrocarbon sand was detected by the DDEM tool about 10 meters below the wellbore. The DDEM reservoir mapping software was used to image the newly found sand body. Based on this new finding, the drilling Bottom Hole Assembly was pulled back and the hole was side-tracked to target this new sand, which was successfully penetrated and completed. This new sand, which would not have been discovered with standard LWD tools has increased the well production by a factor of two or more. Being a turbidite sand, it was not picked up on the surface seismic section. The reservoir mapping software technology, together with the deep sensing resistivity imaging LWD tool, was instrumental in finding the new hydrocarbon sand which has substantially increased the production of Tango Field.
Reactive Transport Modelling of CO2 Injection Into High CO2 Field
Authors: Amin S. Mohd , Azuddin F. Jaafar
Published: October 2016

Gas reservoirs often contain a proportion amount of naturally occurring CO2, ranging from a few percent up to 70% by volume. A carbonate gas field located in offshore Sarawak, eastern Malaysia has a very high concentration of CO2 and expected to be a world pioneer offshore CO2 storage in high CO2 field with the accumulated amount of 70 % mole of the gas in place. Carbon dioxide from the gas field is removed from the gas production stream in a central gas processing facility and then the CO2 is compressed, transported and stored underground in the carbonate reef reservoir of the same gas field. This study details the geochemical effects of CO2 injection into the field as part of the proposed field development. In this study, we ran a two-dimensional reactive transport models using TOUGHREACT. The model was run for 300 years at the temperature of 140°C and pressure of 352 bars. The CO2 was injected for 30 years below gas water contact (GWC) in the aquifer. The modelling results shows that the overall geochemical alterations of injected CO2 into solid phase are minimal and is confined to the region below the original gas water contact with the minimal additional impact on injectivity. This is due to the dry-out formation vicinity to the injection well that lead to the small amount of salt precipitation. These findings demonstrate the importance of geochemical reactions study when injecting CO2 into high CO2 gas field at high pressure and temperature.
Conceptual City-Oilfield Development of a Complex Turbidite Reservoir
Authors: Mishra Shubham , Hii Sing Kiet , Corbett Chip , Noor Amin Edalat , Sharma Sigra
Published: October 2016

This theoretical study about the development of a turbidite reservoir is unique because it considers the combination of the surface and the health, safety, and environment (HSE) constraints of the urban overlying the reservoir. Although geology poses deep challenges in terms of reservoir heterogeneity, anisotropy, compartmentalization, and pressure drives, the attempt to develop oil fields in an urban environment makes it very difficult to plan facilities, transport, services, and operations because of HSE issues. This study is a continuation of a previous study in which the background, modeling, and economic analysis of the earlier study is combined with stronger HSE concepts to make the study more holistic.

With a strong focus on health and environment, this paper establishes guidelines for managing the risks of urban development. Reservoir management is guided by sensitivities and uncertainties on CAPEX and OPEX, establishing novel ways of optimizing infill well locations, drilling practices in a city, and enhancing hydrocarbon production through reservoir simulation practices. The geological, geophysical, and engineering data for the study are generated to represent analogous turbidite reservoirs whereas the HSE well planning recommendations are derived from urban oilfield developments in Los Angeles and Long Beach, California.

The methodology of dynamic modeling is nonconventional in terms of analyzing the field for forecasting immediately after initialization followed by a detailed history match considering the numerous hurdles of turbidite environment. This allows greater time for field development planning, which is conventionally given the least attention because of time constraints. Therefore, the prediction comprises a no-further-action case, an infill wells case, and waterflood scenarios, with a combination of vertical and horizontal well trajectories exhibiting the best output in a span of vast economic sensitivities over multiple scenarios. The most noticeable part of the study is the wide range of realizations on well trajectories, well placement, optimizing drilling, and production services. Our modeled city was Houston, Texas, a well-known urban environment. As a result of the modeling, a technique was developed to guide for environmentally safe development within this example.

The technological and economic conclusions make this a foundation study for profitable development of reservoirs underneath a populated area. The study may also be instrumental in exploitation of turbidite reservoirs, which present challenges in current North Sea and Brazil offshore development and in recently discovered submarine fans in the Gulf of Mexico deep marine environment.
Handling Missing and Corrupted Data in Waterflood Surveillance, Using Reservoir Linear Characterization Models
Authors: Attar Atheer Al , Hughes R. G. , Hassan Omer F.
Published: October 2016

Oil field data are not always accurate and complete. According to Nobakht et al. (2009), corrupted and missing data costs the industry $60 billion annually. Unless extreme caution is taken to collect data, every dataset is expected to have at least 1-5% error from different sources i.e. human error, measurement setup error or measurement equipment malfunction. The main issue when dealing with missing and corrupted data is limited understanding of our data behavior. Better understanding means improved decisions will be made to remedy missing and corrupted data. Generally two methods are used to deal with the missing data: 1- Dropping missing intervals; 2- Estimation of expected missing point values. In this paper, both methods will be tested and applied on missing production and injection rates in waterfloods projects. A simple reservoir model was used to calculate the expected value for the missing values of the production rates, namely the Resistivity Model (RM) by Albertoni (2003). Reverse modelling was utilized to estimate the missing values for injection rates. Several cases were simulated with two missing ratios: low (15%) and high (30%) in both the production and injection data. Missing points were generated in the datasets in the form of four patterns (Arbitrary, Monotone, Multivariate and Modified Multivariate). The missing data locations were selected in a Monte Carlo-like manner and results were averaged from 400 realizations for each pattern. An error rate was obtained for each pattern and missing data from both injection and production rates were considered. The dropping method showed a larger error propagation rate when the modified multivariate mode is in effect. This pattern is expected to happen when there is a systematic accident or problem in the rate measurement devices. Thus, it takes time until the system can be returned to normal measurement. The least amount of error occurs when there is arbitrary missing data that could happen at any time. The recommendation here is that dropping is not an appropriate method if there is more than 3% missing data. The value of R2 approaches 60% quickly once the amount of missing data hits 2% for all patterns. This also helps explain the reasoning behind using only full data sets for a method such as RM. For a case with 15% missing data with data missing from both the injection and production, an R2 value of 0.87 was obtained using the method of imputation presented. This work found that missing more than 6% of the data is the limit for dropping data since the model R2 drops very fast when the amount of missing data is more than 6%.
Application of Subsea Demulsifier Chemicals to Reduce Heavy Oil Emulsion Viscosity and Enhance Production in the Pyrenees Development
Authors: Gilbert M. L. , Morley D. A. , Elliott P. A.
Published: October 2016

The Pyrenees development is located offshore Western Australia, and has been producing since 2010 under the operatorship of BHP Billiton Petroleum. Six heavily biodegraded, low GOR oil fields are developed by 19 horizontal production wells with reservoir sections up to 3000m long. Each field has between 1 and 6 gas lifted production wells connected by separate production and test flowlines to a Floating Storage Production and Offtake (FPSO) vessel. As field water cuts progressed above 10%, an increasing deviation between predicted and actual flowline pressure drop was observed and indicated the formation of emulsions in the wells production tubing and flowlines. The additional flowing pressure loss and consequent reduction in production rates formed the basis for a debottlenecking project to treat subsea emulsions.

After identification of a suitable demulsifier chemical through laboratory testing, chemical treatment was initially undertaken via injection at the subsea manifolds. Initial demulsifier field trials yielded a 4% increase in field oil production.

In an attempt to realise further pressure drop reduction, the opportunity for downhole injection at each well was investigated. As downhole chemical injection had been initially designed for scale inhibitor, flow assurance studies were performed to ensure repurposing the downhole lines would not result in an elevated calcite scaling risk in subsea equipment.

Field implementation of downhole chemical injection across the available wells resulted in an additional 18% field oil production uplift, with individual wells achieving up to 50% increase in drawdown and 58% increase in liquid production. Additional benefits attributed to downhole demulsifier injection include improved gas lift efficiency and stabilised flow regimes and pressures observed at the downhole gauges and topsides risers.

This paper provides a unique case study in opportunity identification and multifaceted problem solving to significantly and safely debottleneck production. An innovative solution was found by relocating the injection location and repurposing existing topsides and subsea equipment with very low additional capital investment. The lessons and processes used in this project may be carried across to other existing fields and facilities to assist identifying and resolving related flow assurance bottlenecks.
What We Have Learned on Shale Gas Fracturing During the Past Five Years in China
Authors: Yonghui Wang , Zhuhong Tian , Lifeng Yang , Xingming Yan , Xinbin Yi , Haibing Lu , Yaoyao Duan
Published: October 2016

Scale development of shale gas in North America has greatly stimulated the enthusiasm of China. Since July 30, 2010 the first shale gas well fracturing, more than 300 wells have been fractured in the past five years in China, an average post-frac production is more than 6E4m3/d for one well. Technology include pre-frac evaluation, the methods of fracturing design, fracturing materials, tools and equipment, gas factory workflow and quality control system has formed.

Basis on the study following recognition can be drawn: ①natural fracture distribution、stress difference and fluid viscosity are the key factors to create the complex fracture; ②geological engineering integration concept has been implemented and application successful; ③formulated the principle to improve SRV+3C (complexity, connective, conductivity), design method of shale gas reservoir stimulation has formed; ④formed including of transverse fracture to the horizontal wellbore set, PNP multi-stage fracturing, "the 3 big 2 low 1 small" (Large amount of liquid, proppant, high injection rate. Low fluid viscosity, sand concentration. Small diameter particle combination proppant) design, real-time quality control techniques, and multi-well simulfrac/zipperfrac technology, gas factory workflow, etc.; ⑤ construction capacity and parameters have reached the normal level of North America. Horizontal lateral up to 1000-2000m, single stage 60-100m, single well stages up to 25; For one stage fluid volume is generally 1600-2200 m3, proppant is normally 60-170t/stage, pumping rate is 8 -16 m3 / min; Usually for zipper-frac 2-4 stages can be finished in daytime, and 6 stages for simul-frac, post-frac production is from 6 to 55 (E4 m3/d) for a single well.

In this paper, not only successful experience on shale gas well fracturing are presented, but also some challenges, such as casing deformation, frature discription, water shortage etc.
Stimulation in High Water-Cut Wells: Treatment Optimization Using a Fluid Placement Model
Authors: Bhatnagar Ankit , Eoff Larry
Published: October 2016

This work discusses application of an advanced placement model for optimizing stimulation treatments in high water-cut wells. Stimulation treatments in high water-cut wells are challenging because they can lead to an undesired increase in water production. Associative polymers have been successfully used as diverters for addressing this challenge, and effective treatments have been performed based on experience and guidelines. However, further optimization of such treatments can be achieved using fluid placement models.

Model-based treatment design has been described previously but has not been comprehensively applied for diversion by associative polymers. In this work, a transport model was developed for relative water permeability reduction by associative polymers and diversion of stimulation fluids in the pay zone. The model accounted for the mass transport and adsorption of the polymer in the formation. The transport model was integrated into a near-wellbore (NWB) fluid placement model to simulate fluid distribution in a heterogeneous layered reservoir and the effect on total skin, production/injection profiles, and surface/bottomhole pressures (BHPs) during the treatment.

The paper describes case studies based on actual field treatments to demonstrate the application of the integrated model for optimizing stimulation treatments. Acid-to-diverter stage volumes, number of diverter stages, polymer concentration, and injection rates are identified as important design parameters. Based on model results, it is observed that polymer placement results in increased total skin in water-bearing zones, leading to lower post-treatment water production. Further, the optimum number and volume of diverter stages for effective diversion vary with injection rate and are governed by the non-equilibrium polymer adsorption behavior and the self-diversion effect during placement. It is concluded a single treatment design might not be suitable across multiple wells, and well-specific optimization of the pumping schedule is necessary. Because multiple parameters affect the treatment, simultaneously leading to results that are not intuitive, the placement model should be used for the treatment design.

This paper discusses application of an advanced fluid placement model, which provides insight into the diversion by associative polymers during stimulation treatments. The model is useful for optimizing stimulation treatments in wells with high water cut and reducing costs associated with undesired water production.
Numerical Modeling for the Prediction of Residual CO2 Trapping in Water-Wet Geological Porous Media
Authors: Jahan Farjana , Ahmed Shakil , Hossain Mofazzal , Iglauer Stefan
Published: October 2016

Residual trapping of CO2 has been identified as a reliable and rapid way to dispose large CO2 quantities. Several experimental investigations have been completed where residual trapping in sandstone was measured; these programmes identified that initial CO2 saturation and rock porosity are significant parameters which influence the residual saturation and thereby residual trapping capacity and effectiveness. In order to further improve fundamental understanding a computational tool need to be developed with which residual CO2 saturations can be predicted.

Pore-scale two-phase fluid flow simulation is performed based on the integration of x-ray micro-tomography images (which provide a detailed description of the rock's pore space) and Navier-Stokes equations. X-ray micro-tomography (approximately (6µm)3 voxel size) images of F42 sand pack were used. The extracted pore morphology of each medium was obtained by segmenting the images based on their greyscale contrast using image processing software AVIZO Fire. These binary images were converted initially into surface and volume meshes which were then fed into a commercially available computational fluid dynamics code (ANSYS-CFX). Three dimensional transient, laminar flow fields were obtained by solving the continuity and Navier-Stokes equations using an Eulerian-Eulerian multi-phase flow approach. To incorporate the effect of capillary forces, free surface model was used which solved the pressure gradient at the interface correctly. The model assumes isothermal condition with no mass transfer between the brine and CO2. The inlet and outlet boundary conditions include CO2 flow rate and the pressure respectively. We simulated the drainage condition in this paper. Approximately 1.5 million tetrahedral elements were used to generate volume mesh, and the convergence criterion for all variables was set to 10-3. Initially all pore space was filled with brine, and then CO2 was injected from one inlet side at constant flow rate, obtained from the experiments. When the system was at connate water saturation, we stopped our simulation. The residual saturation depends on the flow rate of super critical CO2.

The computations described here are a rapid, cost-effective and can reveal vital information for the planning of carbon geo-sequestration projects and associated risk and capacity assessments.
Novel Cementing Solutions to Impede Lost Circulation with Highly Crush-Resistant Lightweight Cement System and Engineered Fibers
Authors: Putra T. , Steven A. , Wedhaswari V. R. , Awalt M. S. , Natanagara B. B. , Pasteris M. , Jaffery M. F. , Sheikh Veisi M. , Rudiantoro A.
Published: October 2016

Seguni field and Sejadi field are smaller regions of Sepinggan field in offshore of East Kalimantan, Indonesia, which were drilled and developed by the operator since 1977. Seguni-V (redrilled well) was prognosed to encounter several depleted sandstone formations with reduced pore pressure due to produced hydrocarbons. Consequently, the utilized drilling fluid density was set as low as reasonably practical and this methodology had successfully prevented any lost circulation event until the total depth (TD) was reached. Nonetheless, the risk of losses were greater in the cementation phase of the 3 1/2-in tubing due to long column of cement (>7000 ftMD) required. Therefore, the challenge was to reduce the cement slurry density that still can achieve a required compressive strength within timely manner. The reduced slurry density was also predicted to be instable downhole due to the immense bottomhole pressure, which might crush the conventional cenospheres in the slurry as lightweight materials and result in an increase of downhole slurry density. Therefore, to minimize the risk of induced lost circulation caused by slurry density increase, a novel lightweight material with highly-crush resistant property was proposed. The result of the job with this cement system was satisfactory with no losses occurred and the targeted intervals were covered with good cement.

Sejadi field, on the other hand, had experienced losses while drilling, from seepage losses which were commonly found, up to 170 bbl/hr of loss rate at one of the wells in the field. A particular lost circulation case with persistent loss rate into depleted formations was observed at Sejadi-X well. 728 bbl of synthetic based mud (SBM) had been lost into the hole when a loss rate of >40 bbl/hr was encountered while drilling 8 1/2-in open hole (OH) section. The loss rate could not be reduced even after spotting three times of 30 bbl conventional lost circulation material (LCM) pill and had cost significant volume of SBM and LCM amount lost to the formation, as well as 2 rig days spent in attempt to cure the loss. The study of the previous failure on similar problems in the neighboring well led to the solution proposal to use engineered, optimized fiber in cement slurry for lost circulation plug. The result was prominently effective and drilling operation could be resumed to total depth.

This paper describes the features, case histories, challenges, field applications, as well as the acknowledged results of mentioned technologies. Lastly, this paper also introduces a mutualistic technical feature when the two technologies are combined to both prevent and mitigate lost circulation.
Mathematical Model and Experimental Study on Drill-In Fluid Loss Control and Formation Damage Prevention in Fractured Tight Reservoir
Authors: Xu Chengyuan , Kang Yili , Li Daqi , You Zhenjiang , Luo Yaohua
Published: October 2016

Drill-in fluid loss is the most important cause of formation damage during drill-in process in fractured tight reservoirs. Lost circulation material (LCM) addition into drill-in fluid is the most popular technique for loss control. However, traditional LCM selection is mainly performed by trial-and-error method, due to lack of mathematical models. The present work aims at filling this gap, by developing a new mathematical model to characterize the performance of drill-in fluid loss control using LCM during drill-in process of fractured tight reservoirs. Plugging zone strength and fracture propagation pressure are the two main factors affecting drill-in fluid loss control. The developed mathematical model consists of two sub-models, i.e., the plugging zone strength model and the fracture propagation pressure model. Explicit formulae are obtained for LCM selection based on the proposed model, in order to control drill-in fluid loss and prevent formation damage. Laboratory tests on loss control effect by different types and concentrations of LCMs are performed. Plugging pressure and total loss volume are measured and compared with modeling results. Effects of LCM mechanical and geometric properties on loss control performance are analyzed, for optimal fracture plugging and propagation control. Different combinations of acid-soluble rigid particles, fibers and elastic particles are tested in order to generate a synergy effect for drill-in fluid loss control. The derived model is validated by laboratory data.
High Performance Water-Based Mud HPWBM: Turning Old Ways into New Opportunities
Authors: Mahrous Ramy , Vader Ronald , Larreal Enrique , Navarro Raul , Salmelid Bjarne , Honey Alastair , Weir Malcolm , Lammers Gert , Rijnen Peter
Published: October 2016

For decades, wells targeting the Rotliegend reservoir in the Southern North Sea Basin have been drilled using conventional water-based mud (WBM) in the top hole section and oil-based mud (OBM) systems throughout the remaining sections of the well. The standard well design generated high waste disposal costs onshore and offshore, particularly with regard to OBM waste. This study evaluates alternative fluid systems to help reduce disposal costs for the operator.

As part of the operator's environmental improvement strategy, the operator and fluids provider team identified potentially significant waste disposal cost savings for an onshore trial. Using a WBM system for drilling top holes as well as through the lower sections could result in cost savings through the reduction of top hole fluid dilution as well as a reduction in waste disposal costs.

A high-performance water-based mud (HPWBM) system with similar performance to an OBM system was proposed as part of a trial to demonstrate these potential savings in disposal costs for an onshore well.

The field trial was a great success compared to conventional fluid systems and methodologies. The well was drilled 11.6 days ahead of schedule and 20% under the planned budget. The time vs. depth curve was on par with what was expected when drilling with an OBM system.

The HPWBM system created a saving of >5% of the total well cost and it was 16% less expensive than conventional fluid systems. A further saving of 2.5% of the total well cost was identified for future onshore/offshore applications of the HPWBM system. It was also theorized that a further reduction in waste disposal costs could be realised in offshore operations.

The field trial was based on a basic onshore well trajectory as a proof of concept. Upon the success of using HPWBM in the basic well, more challenging onshore as well as offshore applications would be examined which have the potential to double the cost savings generated.

This novel approach of using an environmentally acceptable HPWBM system in the Southern North Sea Basin can offer significant cost saving opportunities with regard to waste management for both onshore and offshore wells compared to conventional WBM and OBM systems.
Modelling of Slow Fines Migration and Formation Damage During Rate Alteration
Authors: Yang Y. , You Z. , Siqueira F. D. , Vaz A. , Bedrikovetsky P.
Published: October 2016

Fines migration involving particle detachment in reservoirs often leads to severe permeability damage. It is the consequence of straining of the detached fines in relatively narrower pore throats. Many laboratory coreflood tests indicate that the time of permeability stabilisation can reach hundreds or thousands of pore volumes injected. However, the classical filtration theory assumes that the mobilised fines are transported by the bulk of the carrier fluid, thus the permeability stabilises after one pore volume injected. The current paper attributes the stabilisation delay to the slow drift of the released fines close to the rock surface. We propose the system of flow equations for fines migration in porous media taking into account the velocity of particles lower than that of the fluid. An analytical model for one-dimensional flow with particle mobilisation and straining during piecewise increasing flow rate is obtained. The laboratory data are in good agreement with the results of mathematical modelling. The effective particle speed is 500-1000 times lower than the water velocity.
Integrated Innovative Technology Saves 354 Rig Days in an Infill Drilling Campaign - A Case Study from Bohai Bay, Northern China
Authors: Ma Yingwen , Zhang Binqi , Liu Feng , Li Junbao , Zhang Bo , Wu Kai , Wang Fei , Xu Tianyun , Yu Xiaoning , Zhang Hongyong , Xu Bing
Published: October 2016

Field X, locating in Bohai bay, Northern China, was started to develop in 1999 as Phase 1, relying heavily on directional wells. Since 2013, in order to further increase the final recovery rate, this complex fluvial reservoir oilfield has stepped into Phase 2, with a new infill drilling campaign involving 109 wells, mostly horizontal wells.

Because of the limitation of the authorization for expenditure (AFE), the predominant effort for this infill project was to increase the drilling efficiency. Therefore, it was requested for all the relevant parties to cooperate to enhance as much as possible drilling in a safe manner. Several risks were identified during the pre-drilling comprehensive assessment: Well collision risk at the top section.Achieve sufficient dogleg severity (DLS) while keeping high rate of penetration (ROP) under unconsolidated sand environment.Bottom water existed due to long-term production of this infill project.

To address the above technical challenges, an intergraded innovative approach has been explored by operator and service companies: Multiple preventive and mitigative measures have been applied to minimize the anti-collision risk, such as Gyro surveying on offset wells, shutting down high risk offset wells and casing monitoring, etc.Fit-for-purpose rotary steerable systems (RSS) were used, including the point-the-bit RSS and the hybrid RSS (combining point-the-bit and push-the bit steering) based on the DLS requirements and the previous drilling practices."Distance-to-boundary (DTB)" technology was used to keep optimal distance to target boundary in order to delay the onset of the bottom water and avoid exit from the reservoir, which would result in costly sidetracks.

By using this integrated innovative approach, drilling efficiency has been increased significantly in a safe manner. As a result, 354 rig days have been saved (including drilling and completion only) which represent an improvement of 21.8% compared with the original AFE. Converted to sum, it was an 89.54 million USD reduction. In addition, by the help of precise trajectory placement for the lateral section, the scheduled production rate was surpassed by 37% with 2.5% water cut only as of Mar-2016.

This exemplary case demonstrated how an integrated approach can help to increase drilling efficiency and save budget in an infill drilling campaign. The authors believe that it could be adopted by other similar project, who is seeking for higher input-output ratio under the current oil/gas environment.
Increasing Water Injection Efficiency in the Mature Windalia Oil Field, NW Australia, Through Improved Reservoir Surveillance and Operations
Authors: Haghighi M , O'Reilly DI , Hunt AJ , Sze ES , Hopcroft BS , Goff BH
Published: October 2016

This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.

Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.

The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.

The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
Predicting Reservoir Rock Mechanical Properties Directly from Sedimentary Characterisation
Authors: Liu Keyu , Wu Bailin
Published: October 2016

Twenty-nine core plug samples of a wide range of Uniaxtial Compressive Strength (UCS) values were investigated using a suite of techniques including visual inspection at meso-scale on hand specimens and thin sections, microscopic examination, Scanning Electron Microscopic (SEM) analysis, laser particle analysis and X-ray Diffraction analysis to characterize their compositions, texture and sedimentary properties. An intimate intrinsic link is noticed between sedimentary features observed at meso-scale and that at the micro-scale, both of which can be directly correlated to rock strength. It has been demonstrated that one can empirically predict the rock strength (UCS range) of rocks from an inspection of core plug samples. A Rock Property Index parameter which combines a number of sedimentary parameters is found to be useful in qualifying or ranking the rock strength (UCS) of the samples investigated. A set of criteria of sedimentary characterization is proposed for empirically estimating the rock strength of core samples including the lithological compositions, heterogeneities, cementation, quartz and clay contents, grain contact nature, grain size distribution and visual porosity. This method may be applied to describe cutting samples at rig-site to provide timely information of the strength of the formation rocks while drilling.
Predicting Shallow Marine Reservoir Heterogeneity Using a High Resolution Mapping Approach, Brigadier Formation, NWS, Australia
Authors: Ainsworth R. B. , Payenberg T. H. , Willis B. J. , Sixsmith P. J. , Yeaton J. W. , Sykiotis N. , Lang S. C.
Published: October 2016

Reservoir delineation and characterisation of the shallow marine Triassic Brigadier Formation (Fm.), northwest shelf (NWS), Australia is challenged by the thin-bedded nature of the reservoir. These reservoirs are generally below seismic resolution in stark contrast to the underlying, seismically well-imaged Mungaroo Formation fluvial channel belt reservoirs. In the absence of clear seismic definition of reservoir distribution, development of reservoir models for the Brigadier Fm. rely heavily on conceptual depositional models refined by reference to depositional analogues.

The Brigadier Fm. intervals currently under development in the Northern Carnarvon Basin are typically 120 m thick with overall 50–80% NTG. Strata in this interval are generally structurally inclined in tilted fault blocks and sub-crop an angular unconformity (IJU) with overlying sealing shales. Although the general geometry of the inclined strata is imaged on seismic, poor impedance contrasts do not allow definition of individual sheet-like, five to 10 m thick depositional elements or internal lithic variations that could be used to confidently target development wells. Thick stacked successions of thin reservoirs separated by shale produce correlation uncertainties between wells and make it challenging to predict spatial trends in reservoir quality. In order to better predict vertical and lateral facies patterns within the Brigadier Fm., a novel approach of reservoir mapping and model construction was developed that deterministically predicts reservoir distribution and connectivity based on conceptual depositional models.

A revised Brigadier Fm. stratigraphic framework was created across the sub-regional (88 km x 64 km) study area by integrating the latest sedimentology, biostratigraphy, chemostratigraphy and seismic data. Depositional models of the Brigadier Fm. were reviewed by re-examining core using a depositional-process classification that defined reservoir-element-scale bodies within correlated stratigraphic intervals. Two key depositional scenarios were developed; an asymmetrical, wave-dominated delta model, and an alternative fluvial-dominated delta model. The Mitchell River Delta, north-west Queensland, Australia, was used as a partial analogue to define shapes and scaling of the subsurface depositional elements and their internal lithic patterns.

The sub-regional model produced for the study was built in flattened stratigraphic space. Depositional geometries were extracted from this model and morphed into structured space over specific fields. The hierarchical nature of the model enables seamless analysis of exploration to development scale issues. The model is currently being tested by predicting and verifying the vertical facies successions for exploration, appraisal and development wells, and dynamic flow data from well tests.
Low Cost Strategy and Practice for Low Permeability Oilfields Under Synergetic Multi Disciplinary Systems
Authors: Liu He , Li Ying , Bao Shu Jun
Published: October 2016

As a systematic project and a new development mode, cost-effective development for low-permeability reservoir can be achieved via professional coordination of multi-disciplinary systems. It requires the removal of all unnecessary formalities and expenses, the exploration for gaps and critical weaknesses, the establishment of a strategic framework and organization of low-cost innovation, as well as the integration, conformity innovation and the process innovation, by liberating internal innovators and seeking for external innovators, and by conducting low-cost experiment and respecting the fundamental interests of employees.

The methods of implementation are as after mentioned: 1) to build a consolidated information platform combining by exploration, development and engineering technologies; 2) to upgrade the intensive drilling capacity and the reasonable casing structure; 3) to develop the overall fracturing technologies and advanced process techniques; 4) to enhance the optimized management and measures for day-to-day production; and 5) to contain innovations in enhanced management and system protection.

Focusing on the development of oil and gas resources with extra-low permeability, the appropriate processing plan can be established through synergetic coordination of multi-disciplinary, continuous innovation in techniques and management. The combination of the aforementioned facts forming combined forces to establish a comprehensive low-cost multi- disciplinary innovative system and the market competitive mechanism, to unify the underground natural materials and aboveground artifacts, and to realize the purposes of single well production enhancement and cost reduction.
A Case Study for Deriving and Calibrating Net Reservoir in Thinly Bedded Siliciclastic Formations: Brigadier Formation, Offshore Australia
Authors: Pillai Paul , Douglas Brian , Prabawa Hendrayadi
Published: October 2016

The Brigadier Formation is a thinly bedded reservoir that contains approximately 40% of in-place gas resource in Wheatstone field, which underpins the two-train Wheatstone liquefied natural gas (LNG) project in Western Australia. The development drilling campaign has recently been completed with three Wheatstone development wells targeting the Brigadier formation in the northern part of the field. Accurate and timely determination of net reservoir thickness is crucial not only for evaluating field volumetrics and performance, but also to support time-sensitive drilling decisions. In the case of two of the Brigadier wells, the decision to accept a development well location or move to a contingent well location was required within 72 hours of penetrating the reservoir with a pilot hole. Additionally, TD (total depth) decisions in the Brigadier Formation were made on the basis of real time kH (cumulative permeability thickness) evaluation from logging-while-drilling (LWD) logs and are essential for balancing well deliverability requirements with minimising risk of early water breakthrough by optimising standoff from the aquifer.

A fit-for-purpose approach to calibrate and evaluate net reservoir in the thinly bedded Brigadier Formation will be discussed. Several methods of net reservoir determination have been tested in the Wheatstone field. Standard resolution methods like density-neutron cross-over, and photoelectric factor, and high resolution methods like electrical image logs - water-based formation micro-imager (FMI) and oil-based new generation imager (NGI) - and LWD alpha processed density are compared against core-based sand counts to derive the most reliable and fit-for-purpose method of net reservoir determination. Mud-type, conveyance methods and borehole condition also impacts the results of net reservoir evaluation.

The results from a combined density-neutron-photo electric factor method was found to compare very well to core net reservoir and image log-derived net reservoir, across mud types, reservoir fluids and hole angles. It is locally calibrated and blind-tested successfully across different wells. The nuclear tools are logged in every well in the field so this method of calculating net reservoir could be applied consistently across all wells. An added advantage is that the evaluation of net reservoir is independent of porosity and hence, net reservoir will not need to change with different generations of petrophysical evaluation.
A Cellulose Fracturing Fluid with Instant Solution and No Residue
Authors: Hua Ming , Yongjun Lu , Baoshan Guan , Xiaohui Qiu , Wei Liu , Fa Yang
Published: October 2016

Tight reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during drilling, completion and stimulation operations. These reservoirs have small pore throat size with significant capillary pressure energy suction that imbibes and holds liquid in the capillary pores. Such residues from Guar after gel breaks cause formation damage and low conductivity, and it can significantly reduce well productivity even in tight gas reservoirs. This paper presents a new cellulose derivative of instant dissolution and free of residue. The field test results of the new fluid in tight gas reservoirs in China show importance of minimizing formation damage in a hydraulic fracturing stimulation. Otherwise, the well productivity improvement may not be achieved in the case of excessive residues into formation during hydraulic fracturing operations. A new fluid has been applied in 18 wells in western China and the results show that the new fluid was easy to prepare and rapidly dissolved with no "fish eye", this system can reach 97% of the peak viscosity within 2 minutes, and the surface tension of the gel breaking liquid is 18.44 mN/m. No residue was found after the gel was broken, its conductivity was improved, and the formation damage is less than 13% in the core test. Meanwhile it has excellent properties of proppant suspension. Gas production in multiple wells of the tight gas reservoir increased to 2.13×105 m3/d after stimulation with the new fluid, 4.2 times higher than similar groups of wells using Guar-based fracturing fluids.
A New Structural Geology Workflow to Expedite and Validate Seismic Interpretation in a Structurally Complex Area: A Case Study from Exmouth Plateau, Australia
Authors: Roy S. , Massara P. , Ellwood M.
Published: October 2016

The Exmouth Plateau is a subsided, stretched and rifted continental platform that forms the northern part of the Northern Carnarvon Basin off Western Australia's northwest coast. The plateau is bound on three sides by oceanic crust and consists of more than eight kilometres of Palaeozoic to Mesozoic sediments (Exon & Willcox, 1978). Due to its geological history, the area presents significant structural challenges for interpretation and prospect evaluation. A new structural interpretation workflow has been developed, leveraging the efficiency of working in one single geoscience platform. The workflow reduces interpretation time and improves accuracy compared to traditional interpretation approaches. A significant advantage of this approach is that a structurally validated framework model is one of the primary outputs.

Structural interpretation from seismic data is one of the most important steps in understanding the subsurface. Geoscientists spend a considerable amount of interpretation time picking faults and horizons from seismic data to understand the subsurface structure. A traditional interpretation workflow, commonplace in the oil and gas industry, is to consecutively investigate separate 2D sections and subsequently combine the interpretations to build a 3D picture. This limits the understanding of the subsurface geology in highly faulted, structurally complex areas.

This study involved the application of a new workflow for producing a structurally validated interpretation on 3D seismic data from the eastern part of the Exmouth Plateau. This workflow incorporates seismic preconditioning, fault framework modelling, structural reconstruction and structural analysis techniques to validate the interpretation (Figure A––1). By constructing framework models of the data it is possible to visualize the interpretation in the richness of 3D. This ensures a valid interpretation of the subsurface geology and is critical for subsequent decision-making processes, such as prospect maturation or well-planning. The final result is clean, faulted seismic horizons and a highly accurate structural framework model. This model can then be used for fault throw analysis to understand growth faults and reactivation zones and investigate zonal fault juxtaposition for prospect analysis. The predictive capability of the framework model is key in ensuring exploration success in plays reliant on fault juxtaposition seal. Figure A-1A new workflow to produce structurally validated interpretations in structurally complex regions.

The framework model also becomes the foundation for geo-cellular modelling and further detailed analysis of dynamic behavior. This ensures the verified structural interpretation is carried throughout the entire exploration and production lifecycle.