bluuebunny/crossref_metadata_2025 huggingface dataset:
Parameters Affecting Load Recovery and Oil Breakthrough Time after Hydraulic Fracturing in Tight Oil Wells
Authors: Zanganeh B. , Soroush M. , Williams-Kovacs J. D. , Clarkson C. R.
Published: October 2015

After hydraulic fracture treatment, wells typically produce significant volumes of water, which is primarily recovered fracturing fluid. The amount of fracturing fluid produced back is called load recovery. Single phase water production may continue for several days before oil breakthrough from the formation occurs. A wide range of load recoveries (15%–80%) are reported in the literature, depending on various reservoir, fracture, pumping and operational parameters. This study conducts a comprehensive numerical and statistical analysis to identify the most important parameters affecting load recovery. The sensitivity of oil breakthrough time to these parameters is also investigated.

A fit-for-purpose model was created using a commercial coupled reservoir flow/geomechanics simulator to simulate fracturing treatment and flowback operations. Water and oil production trends, and flow regimes observed in the model, are verified using rate-transient analysis (RTA). The effect of twenty parameters including pumping rate, shut-in time, producing bottomhole pressure, production rate constraint, matrix porosity and permeability, matrix and hydraulic fracture compressibility, relative permeability end points and capillary pressure on load recovery and oil breakthrough time is investigated by utilizing Design of Experiment (DOE). The developed model considers non-uniform leak-off during pumping, providing a better understating of water retention, while the application of the DOE method allows the effect of various parameters and their interaction to be studied rigorously.

A critical finding is that the majority of total load recovery occurs within the first three months of production. Furthermore, matrix permeability, shut-in time, connate water saturation and fracture compressibility, were found to be the most dominant factors, which can impact the load recovery by up to 22%, 15%, 14%, and 13%, respectively. Matrix permeability, production rate constraint, fracture residual oil saturation and shut-in time are four of the prominent parameters affecting oil breakthrough time.

Understanding the impact of operational parameters such as shut-in time and production rate can help industry to implement recycling/disposal options and ultimately optimize load recovery. This can also create significant environmental compliance benefits for operators in addition to benefitting operational efficiency.
Produced Water: Influence of Organic Acids on the Gelation of Fracturing Fluids
Authors: Weissenberger Markus C. , Lee Adrienne , Wasdal Tim
Published: October 2015

Organic acids, such as acetic or formic acid, are ubiquitous in produced waters from petroleum-producing basins. The chosen measurement system was a reversed-phase mode High Pressure Liquid Chromatography (HPLC). This method can overcome the matrix problem of high inorganic ion concentration in produced waters. This is possible due to the usage of a highly hydrophobic stationary phase, which is not interacting with the high amount of inorganic ions present in produced waters.

In extension to the initial publication the influence of organic acids on the hydration and gelation for zirconium and borate cross-linked fracturing systems was determined in detail. This was done with the original brine samples from different locations and with artificial brines which were doped with different organic acids at different concentrations. It could be shown that in the presence of organic acids the usage of borate cross-linked fracturing gels, which requires a high pH of 9 to 11, is impossible due to a hindered crosslinking. Only with economically meaningless loadings of basic buffers the pH could be increased high enough to achieve a weak crosslinking.

As the natural pH of produced waters in the presence of organic acids is around 4, tests were carried out with zirconium cross-linked systems. These fracturing systems, which require a low pH of 4.5 to 5, were tested in both artificial brines and the actual produced waters with organic acids. It could be shown that in the presence of 600 mg/L or 1200 mg/L organic acids a stable cross-linked gel could be achieved. This is possible even in the presence of high salt concentrations up to 250,000 mg/L.

The conclusion of this work is that in the presence of a higher concentration (from around 500 mg/L) of organic acids like formic or acetic acid the substitution of a common borate cross-linked fracturing system with a zirconium cross-linked fracturing system should be considered.
Inflow Performance Relationship for Unconventional Reservoirs (Transient IPR)
Authors: Shahamat Mohammad Sadeq , Tabatabaie S. Hamed , Mattar Louis , Motamed Ehsan
Published: October 2015

Inflow Performance Relationship (IPR) describes a well's inflow rate at various flowing pressures. The conventional IPR assumes stabilized (i.e. boundary dominated) flow conditions. Unconventional reservoirs may take several years to reach stabilization and their performance evaluation involves complex modeling of stimulated reservoir volume (SRV) and requires advanced reservoir engineering knowledge. As a result, some of the traditional IPR concepts and notions are not applicable.

This paper discusses the behaviour of "transient" IPR in comparison to "stabilized" IPR, the meaning of slope and intercept in transient IPR, and the differences between IPR of conventional and unconventional reservoirs. In addition, the effect of production history on transient IPR of a well is examined.

The result of this study is a methodology for generating a "practical" transient IPR for multi-frac'ed horizontal wells. After history-matching the well's performance, the resulting reservoir model is used in a straightforward procedure to obtain the transient IPR in a form similar to the conventional IPR. This means that it can be used with nodal analysis for determining the effect of changing flowing pressure on the inflow rate.

The methodology presented in this paper maintains the simplicity of use of IPRs, yet accounts for unconventional reservoir complications. The "practical" transient IPR can be used directly by the production engineer for optimizing the production performance of a well without the need to get involved in the complexities of reservoir modeling.
High-Resolution Permeability Modeling in Highly Heterogeneous Tight-Oil Reservoirs
Authors: Solano N. A. , Soroush M. , Clarkson C. R. , Krause F. F.
Published: October 2015

A high-resolution simulation model of a highly heterogeneous tight oil rock sample is used to investigate the effects of physical and biogenic sedimentary structures on scaling and anisotropy of absolute permeability at the core scale. Results are compared to routine core analysis (RCA) available for similar samples.

The volumetric distribution, quality and connectivity of different contrasting types of elementary flow units [microlithofacies (μLFs)] are individually evaluated for a highly heterogeneous Pembina Cardium lithofacies. Reservoir properties were measured/calculated at a sub-centimeter scale for a core sample using a combination of x-ray computer tomography, pressure decay profile permeability, and image analysis techniques. The derived high-resolution porosity, permeability, and μLFs distribution represents the primary input to a single phase flow model. This model was used to simulate whole-core steady-state tests from which absolute permeability for different orientations was derived. Several simulation sub samples with random location and volume are also selected for evaluation of the effect of scale/composition on the calculated permeability.

The core sample evaluated exhibits three dominant rock types and a bimodal permeability within the microdarcy (μLFs SS2+SH1) and millidarcy ranges (μLFs SS1). The calculated (from whole core simulation) vertical and horizontal permeability values are in good agreement with actual RCA measurements from offset cores. Despite relatively good reservoir quality associated with μLFs SS1, results from the full diameter core simulation demonstrate that its limited volumetric abundance and restricted connectivity prevent this rock type from dominating the fluid flow process in these rocks. In fact, permeability seems to be dominated by the tighter encasing matrix (μLFs SS2 + SH1), which exhibits average permeability values very close to those reported from routine core analysis.

The methodology used in this work is particularly applicable to the detailed characterization of reservoir rocks with high degree of heterogeneity associated with biological reworking and/or selective diagenetic imprints. The model incorporates statistical variations for several key geological/engineering parameters and offers a direct comparison to results obtained from laboratory measurements.
Transient Pressure Behavior for Low Permeability Oil Reservoir Based on New Darcy's Equation
Authors: Hailong Liu , Shuhong Wu
Published: October 2015

With further progress of oilfields development in China, more and more ultra-low permeability oil reservoirs are being put into production. However, in ultra-low permeability oil reservoirs, pore throats are small and the specific surface area is big. Fluid always has a slow seepage velocity and the relationship between the seepage velocity and driving pressure is a curve, not a straight line. Fluid flow in low permeability porous media does not obeys Darcy's law any more, so traditional well testing interpretation methods may cause error in estimation of ultra-low permeability oil reservoir parameters.

This paper describes problems encountered when analyzing transient pressure tests in ultra-low permeability oil reservoir. The equation to describe the non-Darcy's flow was given according to theoretical derivation and experimental method, and three factors were introduced into the equation to improve the Darcy's law. Based on the new model, the theoretical well test model for dual-porosity media in ultra-low permeability oil reservoirs with complex fractures was derived which allows for the influence analysis of non-Darcy's effect. By using Laplace transform and Fourier transform, the model was solved by analytical solution and numerical method. The analytical solution obtained is accurate and simple by contrast numerical method results. Besides, the curves for the pressure responses were plotted. The effects of parameters including fracture width, fracture length and the position of the fracture on the pressure were fully investigated in detail. The advantage of the solution is easy to incorporate storativity ratio and skin factor. It can also reduce the amount of computation and compute efficiently and quickly. Sensitivity analysis shows that non-Darcy flow mainly affects the transition section between the pure wellbore storage and radial flow region, and the pressure derivative curves exhibit a gentle transition region compared with the Darcy's flow. These type curves give a better interpretation of well testing pressure response in ultra-low permeability oil reservoir.
Best Practice and Lessons Learned for the Development and Calibration of Integrated Production Models for the Cooper Basin, Australia
Authors: Mantopoulos A. , Marques D. A. , Hunt S. P. , Ng S. , Fei Y. , Haghighi M.
Published: October 2015

This paper investigates the best practices and lessons learned for both the development and calibration methods of integrated production models. Consequently, this allowed for the successful application of Integrated Production Modeling (IPM) to large scale and complex petroleum production systems in the Cooper Basin, Australia. The potential for calibrated integrated production models to aid the assessment of production system development, forecasting, operational surveillance and optimization opportunities (flow assurance, integrity considerations, well performance/intervention, incremental approaches to development and back out/pressures) supported the need for an optimum (quality versus resource allocated) and innovative development procedure. A structured workflow for developing and calibrating the integrated production models is presented which allows for an improved ability to create and operate such models. The key development components, and for which illustrative and detailed workflows are presented, are: (1) development of reservoir model, (2) development of required well models, (3) development of required surface facility model and (4) the overall calibration of the integrated production model. Detailed within this paper is the extensive theoretical analysis which was mandatory in determining the use of the most suitable parameters which included vertical lift performance (VLP) correlations, flowline correlations, relative permeability curves (generation and alternatives), inflow performance relationship (IPR), water influx models, micro-string implications and all related considerations and assumptions. The paper emphasizes the trade-off between the required outputs from the application of the integrated production models and the available resources and period of development. The value of information is also highlighted through the importance of data collection and preparation procedures, both technical (pressure and fluid) and organizational (procedures). Furthermore, engineering decisions were found to significantly dictate the accuracy and efficiency of the implemented development process and workflows, in particular related to average reservoir properties, cyclic well behavior and the history matching of system pressures and flow rates within the calibration process. The considerations have been supported by relevant examples throughout the paper.
Optimization of Staged-Fracturing in Heterogeneous Tight Gas Reservoirs of Western-Sichuan Gas Field
Authors: He Songgen , Deng Yan , Guo Jianchun , Xiao Yong , Zhao Zhihong
Published: October 2015

Tight gas plays an important role in the increasing production of natural gas. Staged hydraulic fracturing has been a key technology to make recovery of tight gas economically viable. The JP formation of Western-Sichuan Gas Field is a typically tight gas reservoir with horizontal wells. However, the optimization design of staged fracturing encountered two challenges: Low porosity-low permeability with non-Darcy effect; High heterogeneity with discontinuous distribution of sand bodies and properties variation in the longitudinal direction. The traditional optimization method based on Darcy flow and homogeneous model is not capable in the optimization of fracturing parameters (spacing, length and conductivity) and perforation position.

This paper presents a new design method of "one strategy for one well" with better economical results. Firstly, non-Darcy flow character was measured by laboratory displacement experiment. The relationship between pseudo threshold pressure gradient (pseudo TPG) and permeability was fitted based on quasi-linear flow with pseudo TPG. Secondly, long horizontal section heterogeneous reservoir models were built on the basis of log and geological interpretation, which involves homogeneous continuous model, interbedding model with barrier and heterogeneous model composed of different seepage units. With barriers and seepage units located, fracture parameters include fracture spacing, length and conductivity were optimized for the goal of best economical production with numerical simulation. Thirdly, a model of induced stress from hydraulic fractures was established based on displacement discontinuity theory. Combined with the optimal fracture spacing, the best perforation position was located with the target of low initiation pressure. Lastly, based on fractures parameters and perforation positions, the operation parameters are designed.

The new design method has been successfully applied to 21 horizontal wells with staged fracturing. Microseismic fracture mapping is conducted to evaluate fractures geometry. The results of post-fracture analysis and post-production evaluation demonstrate the benefits of this new optimization method.
Mud Filtrate Invasion and Wireline Formation Tester Cleanup Performance: Modelling and Field Case Study
Authors: Kass S. , Ellis E. , Pourabed H. , Maleki E. , Schumacher G. , Zeinijahromi A.
Published: October 2015

A new generation Wireline Formation Tester (WFT) was used to perform fluid sampling in a subject field as part of an appraisal drilling campaign targeting significant undeveloped conventional oil reserves. The field consists of free gas caps with associated saturated oil intervals that appear as thin rims around anticlinal flanks. Resistivity log analysis predicated a mud filtrate invasion volume of 89L. Approximately 150% of the expected invasion volume (128L) was pumped during sampling. Laboratory results showed that the sampled fluid was still mud filtrate, despite pumping an extra 50% of the estimated volume required for hydrocarbon breakthrough.

This paper presents a mathematical model for predicting filtrate invasion and post drilling WFT cleanup performance. A new methodology is developed to incorporate critical shear stress concepts into mud filter-cake thickness and filtrate invasion calculations. The mathematical model is used to provide input data for Eclipse reservoir simulator (E100) and an analysis of the field case. The model can also be applied as a predictive tool for filter-cake development, filtrate invasion and pump-out volumes required during fluid sampling. In addition, the model can be used to design optimal mud properties that minimize filtrate invasion and extra treatment of the invaded zone post-drilling. The mathematical model is integrated with reservoir simulation to model the cleanup process.

The mathematical model developed in this study predicted an invasion volume of 528L, which is significantly greater than what was estimated based on resistivity logs (89L). This implies that filtrate invasion volume in the field case was underestimated. A sensitivity study showed that filter-cake permeability was the greatest determinant of filtrate invasion volume, and that radius of filtrate invasion was the greatest control on mud filtrate cleanup during sampling. Reservoir simulation provided a good match between model simulation results and field data.
Experimental Analysis of ESP Performance in Pipe Flows Including Methane Hydrate
Authors: Shimizu T. , Yamamoto Y. , Tenma N. , Narita H.
Published: October 2015

Centrifugal pump performance of electric submersible pump (ESP) is analyzed experimentally during emulsification process in methane-water pipe flows. The ESP is installed in a horizontal pipe section of a flow loop. The flow loop is placed vertically with the total length of 10.4 m, which is composed of the stainless steel pipeline of 2.1 cm inner diameter and the upflow test section of 5 cm inner diameter. The system temperature is kept isothermally at 4 °C and the initial gas-phase volume fraction is fixed at 0.016 while the pump speed and the flow rate are varied up to 2500 rpm and 50 L/min, respectively. The flow regime of the initial gas-liquid flows is determined to be turbulent bubbly flows. Transformation of vapor methane into solid methane hydrate is made by elevating the system pressure up to the super cooling condition through water injection. The detail emulsification process is characterized with use of a high speed camera and in-situ particle size analyzer, both of which are located at the pump downstream. The particle size analyzer employs the focused beam reflectance measurement (FBRM) technique.

It is found that the extent of phase transformation is limited by the pump speed as it determines the smallest size of bubbles generated in the flow line. Emulsion is appeared to be white-opaque, which is made by clouds of microbubbles encapsulated by methane hydrate. The opaque particles can be detected by FBRM and exhibit uniform size distributions, indicating that the particles are emulsified homogeneously in the entire flow domain through fragmentation and coagulation kinetics. The majority of methane hydrate particles are appeared to be transportable by the bulk fluid though some particle deposition on the viewing glass window can be occurred. Higher water power is given by the ESP under the emulsified flows than that of water-only flows, indicating that the apparent fluid viscosity can be increased by methane hydrate particles emulsified in water solution.
Improving the Wellbore Stability While Drilling Long Open Hole Shale Intervals in Tahe Oil Field
Authors: Zhong Hanyi , Qiu Zhengsong , Chen Ganghua , Huang Weian , Dong Bingqiang , Zhang Daoming , Fu Jianguo , Tong Shiquan
Published: October 2015

In order to accelerate the drilling speed and reduce the drilling cost, the well structures were simplified in Tahe oil field in recent years. As a result, the length of open hole section increased dramatically, even as high as 4700m for some wells, and different formations including active shales, gypsum, and limestone were encountered in the drilling process. Drilling in such long interval of open hole undertook the risks of cavings, stuck pipe, hole enlargement, lost circulation and so on because of the complex formation and changing pressure gradients. Therefore, highly inhibitive water-based drilling fluids were essential to improve the wellbore stability of the challenging sections.

To understand the mechanisms of shale-drilling fluid interactions when exposed to water-based drilling fluids, the morphology and mineralogy of shale samples were characterized via scanning electron microscope (SEM) and X-ray analysis. Meanwhile, inhibitive evaluation methods such as swelling test, dispersion test and cation exchange capacity (CEC) test were carried out to analyze the interaction potential of shale samples from the open hole intervals. The results indicated that for the upper interbedded sandstone and shale formation, impressive content of clay minerals (mainly smectite) and weak bonding were contributed to the high potential of swelling and dispersion. While for the deep brittle shale formations, the content of clay mineral (mainly illite and illite/smectite) was also relatively high, and micro-fractures were observed, which provided the access of water invasion.

After analyzing the wellbore instability mechanism of the open hole interval, different drilling fluid strategies were proposed according to the reactivity of formations. For shallow formation, polyamine polymer water-based drilling fluid was selected to suppress the hydration and dispersion of reactive shales. While for the deep formation, polyamine and sulfonated polymer water-based drilling fluid was optimized, in which polyamine as shale hydration inhibitor, sulfonated asphalt and superfine calcium carbonate as microfracture sealing agent were used in combination to realize the chemical and physical stability of brittle shales.

The optimized inhibitive water-based drilling fluids in laboratory were successfully transferred to the application in the long open hole intervals of Tahe oil field. The field application in this area resulted in reduced cost, improved gauge hole and reduction in total NPT. No complicated problems occurred in the field trial. The application indicated that elaborately designed drilling fluids reached satisfying results.
Fundamental Investigation of Mechanical Properties of Additives and Class H Cement Under Downhole Conditions
Authors: Li Li , Boncan Virgilio C. , Brandl Andreas , Jordan Andrew K.
Published: October 2015

The foremost function of primary cementing is to achieve zonal isolation and ensure long-term cement integrity during the lifetime of the well. Current advanced drilling and cementing technologies enable the production of oil and gas in more complex and challenging conditions such as deep wells and unconventional wells either onshore or offshore. Understanding the mechanical performance of cement sheath under downhole conditions, therefore, is crucial for successful cementing operations. Unfortunately, most published mechanical data were still limited to the compressive and tensile strengths determined at ambient condition as well as Young's modulus. The result for tensile strength varies greatly due to the lack of API standard tensile strength testing.

The purpose of this study is to evaluate the additive-additive interaction on cement mechanical properties. Individual additives and their combinations were mixed with class H cement at a density of 16 ppg and cured under elevated temperature and pressure. The mechanical properties tested at ambient and curing conditions include compressive, tensile and yield strength, Young's modulus, and Poisson's ratio. The cement mechanical performances measured at curing conditions, especially the tensile strength, were different from the results obtained at ambient conditions. The elasticity of cement was improved by fiber and polymeric additives tested in this work. This study provides comprehensive experimental data on how the slurry formulation, chemical characteristics of the additives, and additive-additive interactions can affect cement mechanical properties. This study also gives insights into the correlations among various mechanical properties, and the key parameters that could determine cement elasticity. The results can be used as direct guidance for future field applications.
Unlocking Oil Potential in Mature Field Using Linear Rod Pump
Authors: Putro Wiarto Aryoso , Edy I Ketut , Saputra Reza , Anantokusumo Ferry
Published: October 2015

Mutiara is a mature field located in the onshore part of East Kalimantan which has been on production for over 30 years. The field is dominated by gas reservoirs with a much lower presence of oil reservoirs. Production mechanisms range from natural depletion to weak and strong water drive, particularly in some of the shallow areas. High decline rates are very common, which results in a very dynamic and challenging environment. The main artificial lift used in this field is gas lift. However, this method is not efficient for depleted or high water cut wells. Another issue is oil wells which located in remote areas which need high investment for surface facilities including gas lift line network and sufficient pressure to lift the oil up to the surface. Therefore, more and more wells will be idle without implementation of other artificial lift systems techniques.

Several downhole pumping types have been assessed to tackle these issues such as Electric Submersible Pump (ESP), Progressive Cavity Pump (PCP), and Linear Rod Pump (LRP). Considering hilly swampy conditions of the field that requires more compact type of surface unit and flexible to match displacement rate to well capability as well declines. It is then decided to use LRP to unlock oil potential in idle wells.

The first installation of LRP was on September 2014 in X-1 well, this well is the first well drilled in 1982. This installation succeeds on bringing back the well on production. The application of LRP provides opportunity to unlock oil potential from idle wells in this mature area thus maximizing reserve by gaining a few more hundreds barrels of oil per day during the first year.
A New-Simple-Effective Analytical Approach to Determine Intermittent Gas Lif Parameters
Authors: Tasmi Tasmi , Rahmawati S. D. , Sukarno P. , Siregar S. , Soewono E.
Published: October 2015

Intermittent gas lift is commonly known as one of artificial lift technique that is implemented into wells with low bottom-hole pressure. The injection process will be in cycles with spesisified period. Previously, intermittent gas lift is modeled using nodal analysis method, which is intersection between inflow performance relationship (IPR) and tubing performance relationship (TPR) and mechanistic method. Both solutions required a hard-working numerical approach to solve the model. In this paper, a new-simple-effective analytical approach is introduced to solve a set of equations that was derived from Transport Reynolds Theorem. The work is slightly different from the Liao and Bordalo model. A complex equation that represents movement of the gas-column, the slug, and the film from surface to sub-surface is presented. Gas column is formed during the injection time and the injected gas will push the oil to the surface. The dynamics of the gas column greatly affect the success of the process of oil production with gas injection method intermittently. The gas-column pressure, surface injection pressure and rate, gas column density, and surface gas injection density are successfully obtained using this approach. The gas-column pressure in the tubing is strongly influenced by the surface gas injection rate. By controlling the surface gas injection rate then the column-gas pressure in the tubing will be stable. The stable gas-column pressure leads to the stable oil production. This research is genuinely believed to be the first analytical approach of determining intermittent gas lift parameters. The results are give huge advantageous and applicable either for the educational as well as industrial purposes.
Improve the Performance of CO2-based Fracturing Fluid by Introducing both Amphiphilic Copolymer and Nano-composite Fiber
Authors: ZHANG Jin , MENG* Siwei , LIU He , LV Xinrun , ZHANG Rong , YU Baihui
Published: October 2015

Liquid CO2 fracturing is an outstanding stimulation treatment for unconventional reservoirs, such as coal-bed methane reservoir and shale gas reservoir. However, the viscosity of liquid CO2 is extremely low, only 0.03 ~ 0.10 cp under reservoir conditions, resulting a very poor proppant-carrying capacity. Meanwhile, liquid CO2 is a kind of Newtonian fluid, its friction is very large. All these properties greatly reduce the stimulation results.

A novel copolymer composed of CO2-philic fluoride and CO2-phobic partly sulfonated styrene is synthesized. Computer simulations show that these copolymers can create the macromolecular structures via non-covalent association, thus will greatly thicken CO2. Experimental tests showed that this copolymer can increase the solution viscosity 100-fold relative to neat carbon dioxide at 333K and 28 Mpa with a concentration of 1 wt %.

A new kind of nano-composite fiber is also introduced to further improve the performance of the CO2-based fracturing fluid. This nano-composite fiber is synthetized by introducing nano-particles in the conventional polyester fiber. A novel CO2-based fracturing fluid with both the amphiphilic copolymer and the nano-composite fiber added was then developed. A series of evaluation tests were performed in laboratory. The results showed that this fiber can disperse easily in the fluid and an addition of very small amount (0.5%) can enhance the proppant-carrying capacity drastically. At 263K and 28MPa, friction can be cut by 17% via adding 0.5% nano-composite fiber under the shear rate of 5000s−1. Meanwhile, nano-composite fiber can prevent backflow of proppant effectively. Leak-off of fluid can also be mitigated significantly.

The addition of both the amphiphilic copolymers and the nano-composite fibers can significantly improve the performance of liquid CO2 fracturing fluid, thus may greatly enhance the stimulation results of the liquid CO2 fracturing.
A Novel Dynamic Model to Simulate Waterflood Induced Fractures in Low Permeability Reservoirs
Authors: Fan Tianyi , Wu Shuhong , Zhang Xiaozhou , Wang Baohua , Li Qiaoyun , Li Xiaobo , Li Hua
Published: October 2015

In China, a number of low permeability reservoirs have few fractures at the first stage of development, such as Ansai Oilfield in Changqing and Xinmin Oilfield in Jilin. However, they show fracture influenced characteristics gradually with the processing of waterflood later on. It could be attributed to the waterflood induced dynamic fractures generated during the waterflood process. The presence of the dynamic fractures could lead to volcanic water flooding and directly impact the effectiveness of reservoir development.

Based on abundant field data and laboratory data, a new dynamic model to simulate waterflood induced fractures in low permeability reservoirs is established. Compared with the existing models of dynamic fracture, this new model describes the dynamic variation of morphology and permeability of the fractures changing with the formation pressure simultaneously. Thus, this model gives higher reservoir simulation accuracy.

In this thesis, the influences of dynamic fractures on water cut of production well, the water injection timing and the water injection pressure are discussed respectively. Simulation results show that dynamic fractures significantly influence the development effects of low permeability reservoirs.

This model can predict the development results of low permeability reservoirs with dynamic fractures. It gives guidance to adjust the strategy of injection wells and production wells in time. Thus, oil recovery and economic benefits could be increased.
Increasing Brown Oil Field Recovery Factor by Integrated Subsurface Review, Drilling & Workover Operation, and Surface Facility Reconfiguration – Case Study: Rama E Platform Reactivation
Authors: Afi Futiha Nur , Dondo Maximilian , Ratna Nova , Aji Wahyu Seno , Noviansyah M.. , Nurdin Syaiful , Maulana Anton , Hadi Wiryono , Adi Frans , Pentury Nootje , Setiyaka Ary , Pasaribu Martua , Ramadhi Priya , Gunawan Hendrata
Published: October 2015

Deal with brown oil field with runlife of the production more than 35 years has many challenges. Pressure depletion was one of the main concerns of maintaining survival of the field. From the geological aspect, reservoir which produced from limestone was also have many challenges, especially for heterogeneity of the reservoir. Both problems were faced in Rama field which impact the low recovery factor of this brown limestone field. Some approaches was held to increase oil recovery of this field, integrated sub surface review was done aggressively to bring some concept and followed up by some efforts from drilling, workover also surface facility.

Rama field was developed in 1975 with the initial production was about 20,000 BOPD. As of June 2009, Rama field has been producing more than 137 MMBO with production ± 4,000 BOPD mainly from Upper Baturaja. A waterflood project was held in the field from 1982 until 1991 where a large amount of sea water had been injected into Baturaja formation. As the result, the reservoir pressure increased and maintained from 700 psi into 950 psi during the water flood period. However, early water breakthrough was occurred as well and got the water cut jumped into more than 90% from initially 60%. In some wells the water cut could be as high as 99%. Due to its bad impact on the oil production the water flood project was suspended in 1991. Ten years later an oil re-saturation phenomenon has been observed from some wells produce from Upper Baturaja with water cut in the range of 50–90%. The oil production rate from Upper Baturaja was 3,000 BOPD with 85% - 90% water cut. In early 2009 two infill well was drilled and one well was reactivated and gave good indication of decreasing water cut

Rama E wells are among the wells that got bad impact from massive waterflood due to water cut increase, and one by one those wells are abandoned. The platform itself has been abandoned since 1999. Regarding good result of two infill and one reactivation wells, it was proposed to reactivate Rama E platform by modification of Rama-E platform include refurbishment of existing platform, installation of mezzanine deck, Power Control Room, iso-transformer, production process piping and equipment. Reactivation of the wells themselves would be done using jack up rig and snubbing unit.

The objective of this project is to add oil reserves and production with sufficient cost by doing reactivation abandoned platform without drilling new wells.The recovery factor by June 2009 from Upper Baturaja is estimated 14% (OOIP ≈ 505 MMBO). By reactivation of five wells in Rama E, reserve increase up to 631 MBO (2011), it was increase recovery factor significantly.
Operating a Philosophy - Shale Gas Efficient Development in China
Authors: Liu He , Yan Jianwen , Yang Qinghai
Published: October 2015

The Shale Gas Revolution began to have a significant impact on global supply and demand of natural gas, also the price trend of natural gas has been greatly affected. This phenomenon aroused concerns among natural gas producers and consumers. China has abundant shale gas resources, but the development scale is small while facing problems including weak exploration and evaluation basis, overlapping royalties, complex terrestrial environment, lack of technical practices and accumulation, inadequate management and regulatory mechanisms, etc. To overcome these challenges for large-scale shale gas development, we believe that shale gas development is not only a single technical problem, but a systematic engineering demanding multidisciplinary research that will be bound to spread to humans, nature and society. Therefore, to ensure the healthy development of China's shale gas, it is required to coordinate global and local relationships, engineering and community relations, and to break up the conflicts between engineering and nature, engineering and economy, as well as engineering and society.
A Novel Calculation Method for HPHT Deep Gas Well Control
Authors: Elgassier Mokhtar M.
Published: October 2015

When a wellbore is completely or partially filled with gas and work over or drilling operations are to be carried out on the well, it is necessary to bleed off the gas and replace it with liquid or mud to maintain well control.

The replacement of the gas in the wellbore by liquid is commonly done in small stages with gas being released after each stage. This procedure usually requires a long time and could lead to adverse consequences.

The method proposed in this paper will enable engineers to determine in advance the exact volumes of liquid necessary to pump into the well and the exact volumes of gas to bleed off after each injection so that the bottomhole pressure always stays above the formation pressure but below its fracturing pressure. The method takes into account the integrated pressure calculation due to a real gas column in the wellbore. Thus, the variation of the gas deviation factor with pressure and temperature of the gas in the wellbore is taken into account. The results obtained assuming real gas behavior vs. ideal gas can be significantly different in the number of stages, volumes calculated and pressures especially for deep high pressure and temperature wells. Two calculation procedures for the volumes and pressures are presented in the paper. These procedures are outlined step by step in the paper. The procedures are fast and eliminate the need for unnecessarily small injected liquid volumes and remove the element of guessing and the danger of unforeseen consequences.
Effects of Adsorption and Confinement on Shale Gas Production Behavior
Authors: Zhang K. , Wang M. , Liu Q. , Wu K. , Yu L. , Zhang J. , Chen S.
Published: October 2015

Shale gas becomes an important natural gas supplier in recent years. The technologies including horizontal wells and hydraulic fracturing drive the booming of shale gas industry. Gas in shale reservoirs is stored as free gas in both mineral pores and natural fractures, as well as absorbed gas on pores surface. The effect of gas adsorption is generally ignored in conventional reservoirs. However, the absorbed gas has to be taken into consideration for shale gas production because of its huge amount in nanoscale porous media. The smaller the pore throat radius, the more significant is the effect of confinement. Therefore, production behavior can be altered by the effects of adsorption and confinement in shale gas reservoirs. On the basis of Montney shale gas reservoir modeling, effects of adsorption and confinement on shale gas production behavior are investigated in this paper. Results show that total gas production increases with the consideration of adsorption and confinement effects. As gas density and viscosity decreases prior to condensation occur with the effect of confinement caused by nanoscale pore throat, incremental of density difference between free gas and absorbed gas will delay the production of absorbed gas. Moreover, the difference between the amount of free gas produced and absorbed gas produced become larger with the effect of confinement during reservoir depletion.
Application of Plume Cooling Technology to Solve a GTG Impingement Problem - A Case Study
Authors: Thompson J. , Crampton R.
Published: October 2015

Exhaust plumes from generators, pumps, and compressors aboard offshore platforms pose a hazard to crew and equipment. Mitigation for exhaust plume impingement has traditionally been achieved by locating the exhaust uptake away from sensitive areas of the platform, either by use of long horizontal duct runs, a very tall exhaust stack (> 20m), or some combination of the two. These solutions result in an exhaust system that is complicated to design and that adds a lot of weight to the platform. A more practical and weight efficient alternative exists: plume cooling.

Plume cooling technology has been in use for more than 40 years on military ships for the purpose of infrared signature suppression, and for the protection of sensitive weapons and communications systems that would otherwise be damaged by hot impinging exhaust gases. The operating principles of a plume cooler for application to the offshore oil industry are the same as for a military ship. The use of a plume cooler allows for a more compact and lightweight exhaust, but surprisingly this technology has only started being applied on offshore platforms in the past couple of years.

The authors of this paper have more than 28 years of combined experience in the design and manufacture of plume coolers for diesel and gas turbine engines. In this paper the authors present a typical plume impingement problem aboard an offshore platform: an LM2500 gas turbine generator (GTG) that is located centrally in close proximity to the helipad, derrick and deck crane. Using the tools they have developed for plume dispersion analyses on military ships, the authors present the predicted impingement impact of the baseline exhaust on areas of interest (AOI) on the platform as well as the benefit of applying plume cooling. A comparison is also provided between the plume cooling solution and the traditional solution of raising the exhaust stack height, with weight being a main point of comparison.
A Comparison Study of Utilizing Optimization Algorithms and Fuzzy Logic for Candidate-Well Selection
Authors: Xiao Yong , Guo Jianchun , Songgen Songgen
Published: October 2015

It is widely acknowledged that 80% of oil and gas reservoirs in the word are capable of producing at commercial rate only when it is hydraulically fractured, but a good reservoir quality of itself is the resource of production after fractured. Therefore, it is evident that adoption of this technology needs strenuously considerable efforts in candidate-well selection. This paper presents a novel approach of candidate-well selection by combining fuzzy logic, gaussian membership function, multi-level grey correlation analysis, imperialist competitive algorithms with artificial neural networks, fuzzy C-means clustering and C4.5 decision tree in one of heterogeneous gas reservoirs in China. Firstly, the model of artificial neural networks, fuzzy C-means clustering and C4.5 decision are introduced. Then, in comparison with the calculation processes and results, a detailed gas reservoir case is employed to prove the differences among them. Case study verifies that not only the parameters of membership degree and weight can be obtained by fuzzy logic, but also more accurate prediction of gas production and results of candidate-well selection.
Revealing the Uncertainty of Heterogeneities in Fractured Basement: A Case Study from the South Malay Basin Offshore Peninsular, Malaysia
Authors: Gaafar Gamal Ragab , Najm Ehab , Ming Wu Ivan Zhia
Published: October 2015

Fractured basement reservoirs represent more than 20% of the world's oil and gas reserves. Because of their heterogeneity and complex, unconventional natures, the process of mapping the reservoir properties presents a monumental task. The identification of the high productivity zones in basement reservoirs presents a major challenge because of the drastic vertical and temporal variation in porosity and permeability.

Reservoir characterization in terms of rock-forming minerals, multipore system analyses, hydrocarbon typing and quantification, and textural variations can be performed by combining quad-combo, elemental spectroscopy, and resistivity-imaging measurements, regardless of the conveyance technique, in an integrated workflow.

Because fractures play a major role in hydrocarbon production, rapid reservoir decline, and undesirable fluids breakthrough, fracture description is crucial. Aside from conventional techniques to quantify matrix porosity and permeability, a workflow has been designed to provide additional unconventional techniques for multipore system analyses using high-resolution resistivity imaging. With one technique, the resistivity image is sculptured using an object-oriented filter that produces fracture density, aperture, and porosity. The other technique is based on a transformation of image conductivity to porosity that is classified into a matrix and secondary pores to estimate their contribution to permeability.

The multipore system analysis is then used to determine the cementation exponent parameter needed for hydrocarbon quantification. Finally, critically stressed fractures are identified, using geomechanical analyses, to determine the production-contributing fractured zones.

Although the technique/workflow used is relatively new and uncommon for data acquired while drilling, its results successfully met the objectives of the study with quality deliverables.

This paper presents a basement reservoir characterization study with a discussion of the technologies used in the workflow, study results, conclusions, and recommendations for future work. Data used in this work were obtained from a well in Malacca, Malaysia.
Impact of Model Parameterisation and Objective Choices on Assisted History Matching and Reservoir Forecasting
Authors: Hutahaean J. J. , Demyanow V. , Christie M. A.
Published: October 2015

Assisted history matching (AHM) can be approached either by single objective (SO) or multi-objective (MO) optimisation. AHM generates multiple matched-models, which are then used to quantify uncertainty of the forecast. The goals in this framework are not only to produce matched-models in an efficient way but also to provide a reliable forecast under uncertainty. Choice of the model paramaterisation is one of the sources of uncertainty in reservoir modelling. This is usually done based on geological information and engineering knowledge.

This paper explores the impact of different geological model parameterisations on AHM and its impact on the reservoir forecasting. It compares the performance of SO and MO AHM approaches under different model parameterisation. In the MO approach, different choices of objective grouping were studied. Three performance measures in AHM and forecasting will be discussed, namely: diversity, convergence, and forecast reliability. Diversity is defined as set of models that are different but still match history. Convergence is defined as how fast history matching achieves the desirable match. Reliability, for synthetic case study in the present paper, is defined as encapsulation of a simulated truth case into the probabilistic range of forecasting (P10 – P50 – P90).

Study on a standard industry benchmark case in this paper shows that MO optimisation approach provides a more diverse set of matched-models, which leads to a better forecast. It also confirms that a MO approach is more robust and reliable in forecasting than SO under different model parameterisation. Different objective grouping choices in MO approach still give a reliable reservoir forecasting, although variability in convergence rate is seen.