bluuebunny/crossref_metadata_2025 huggingface dataset:
Protecting and Commercializing Advanced Petroleum Technology: The Role of Intelligent Energy Law in 2016
Authors: Fraser H. G. , Dodd J.
Published: September 2016

The world of energy sustained a threefold shock to the system as the industry rolled into 2016. First, the impact of the COP21 Agreement reached on 12 December 2015 in Paris stressed the need to focus on the reduction of carbon emissions had arrived definitively. This brought sharply into focus the International Energy Agency's proposed a "Bridge Scenario" which, it is claimed, could deliver a peak in energy-related emissions by 2020, relying solely on proven technologies and without changing economic development prospects of any region by virtue of five key initiatives: increased energy efficiency; the progressive reduction and phasing out of inefficient coal-fired power plants; phasing out fossil fuel subsidies by 2030; reducing methane emissions in oil and gas production; and increasing investment in renewable energy technologies from US$270 million in 2014 to US$400 billion in 2030.

Second the declaration, following the confirmation of the International Atomic Energy Authority, on 15 January 2016 that Iran had satisfied the conditions for the implementation of the Joint Co-operation Plan of Action signaled the return of one of the world's few three million plus barrels per day suppliers of petroleum to the international market. The Iranian supply side impact paralleled with recurring concerns about the health of the Chinese economy and the impact on the demand side as the industry grappled to understand the longer term impact of the 30% downward lurch in the value of listed Chinese shares in July 2015.

Thirdly, no doubt influenced by the above developments, the price of oil slumped to US$27 a barrel dispelling hopes of an early recovery in 2016 and raising existential fears for those in the industry focused on higher cost exploration and/or production segments of the industry such as deepwater, shale gas and tar sands/heavy oil. The North Sea, with a cost base in the US$50 to US$60 dollars a barrel range breathed in and held its breath. Although the OPEC nations committed not to raise production levels, it was clear that the current down turn was no simple repeat of 1986 and 1998 and different dynamics and forces were at large.
A New Method to Calculate Effective Permeability of a Naturally Fractured Carbonate Reservoir from Seismic Attributes
Authors: Li D. , Alharbi M. S. , Ottinger G. , El-Awawdeh R. T. , Brunhuber P. , Al-Jasmi S. M.
Published: September 2016

Modeling permeability of naturally fractured reservoirs for simulation studies and field development planning is very challenging since the data required for characterizing the magnitude and distribution of reservoir fracture permeability is very limited. Fracture permeability is traditionally measured from cores and/or estimated from well tests. These estimations usually work adequately at well locations for permeability modeling but poorly between wells. Modeling fracture permeability distribution between wells and/or away from wells is a very important step to build a reliable reservoir simulation model for business needs.

This paper presents a new method/workflow for modeling effective permeability of a naturally fractured carbonate reservoir from seismic attributes. The new method directly converts fracture textures and distributions from seismic attributes into permeability for reservoir simulation. Core and log data are used to create fracture regions and the distribution of fracture density; well test data are applied to generate isotropic permeability; and seismic attributes (e.g., ant-tracks, curvature, and anisotropy) are utilized to model the fracture network and permeability anisotropy. New equations are created to calculate effective permeability of the reservoir by scaling up and down between core/well test and seismic data. Two history match parameters (fracture network connectivity and permeability anisotropy) are introduced to assist the history match process within the guidance of seismic and geologic data.

The new method/workflow has been successfully applied to solve the history match challenges of a naturally fractured reservoir in a Middle Eastern field for which no history matched model was achieved before. Applying the new method has significantly improved water movement matches in all producers of the field.
Numerical and Experimental Investigation of Polymer-Induced Resistance to Flow in Reservoirs Undergoing a Chemical Flood
Authors: Hoteit Hussein , Alexis Dennis , Adepoju Olaoluwa O. , Chawathe Adwait , Malik Taimur
Published: September 2016

Polymers are commonly used in chemical EOR flooding to provide mobility control to the injected fluid slugs. Water-soluble polymer injection in porous media usually results in polymer entrapment in the subsurface formation from adsorption, mechanical trapping, and hydrodynamic retention. These different entrapment mechanisms lead to permeability reduction (Rk). The term resistance factor (RF) is used to measure the impact of permeability reduction and viscosity enhancement from the polymer. The residual resistance factor (RRF) represents the residual permeability reduction to chase fluids (usually water) following a polymer flood. These phenomena are more prevalent in high molecular weight polymers. The effects of RRF are also sometimes evident when polymer injection is suspended (e.g., operational issues) and other fluids are injected in the formation instead.

Post-polymer chase water injection is considered a viable option to improve economics of a polymer flood. Current models validate this optionality because they overestimate the efficiency of the chase water flood. Lab and field observations indicate that chase water after chemical flood can cause rapid breakthrough, and therefore it is generally not recommended. The shortfall lies in the assumption that permeability reduction during polymer flood is an irreversible mechanism and therefore the existing simulation models assume that the permeability reduction during and post-polymer flood is the same. In this work, we show that the permeability reduction mechanism can be somewhat reversible, and therefore the current models underestimate chase water injectivity, and more seriously can overestimate the efficiency of chase water displacement. For optimizing the slug size, over predicting chase water displacement efficiency has a critical impact on the project economics and it may wrongly indicate premature switching time from chemical to water injection.

We provide an alternative permeability reduction model that does not assume irreversibility. The new model decouples permeability reduction during polymer flood from RRF during chase water flood. We validate the model using experimental data. Several test cases are provided to compare the two models and we finally demonstrate the applicability of the proposed model in an onshore polymer flood pilot. The new model also highlights the seriousness of the inefficiency of the post-polymer chase water injection.
Methodology for Development of Laboratory-Based Comprehensive Foam Model for Use in Reservoir Simulation of EOR
Authors: Abbaszadeh Maghsood , Varavei Abdoljalil , de la Garza Fernando Rodriguez , Pino Antonio Enrique , Salinas Jose Luis , Puerto Maura C. , Hirasaki George J. , Miller Clarence A.
Published: September 2016

An integrated methodology is presented for development of a comprehensive empirical foam model based on tailored laboratory tests and representative numerical simulations that encompass processes of foam generation, coalescence, shear thinning along with rheological characteristics and flow regimes. Multitude of steady state and unsteady state laboratory experiments of foam floods in a vertical column of sandpack with and without oil at different surfactant concentrations and at varied gas-surfactant solution injection rates are designed, conducted and analyzed. The logic and basis for the conduct of each of these experiments are provided. Test results from experiments in the presence of oil provide information on the oil-induced foam-lamella coalescence functions. Unsteady state experiments are conducted to characterize foam generation and foam dry-out phenomena, while steady state experiments capture the effects of foam quality, foam velocity and surfactant concentration. Process-based numerical simulations of these experimental results are combined with analytical solutions of foam flow equations to provide a methodology for comprehensive foam model. Simulations of unsteady state foam flow experiments with and without oil saturation quantify the foam generation and coalescence function parameters. A procedure is presented to fully model the effect of surfactant concentration on foam strength and quantify all concentration function parameters, and in particular, epsurf. The combination of sound mathematical principles of governing foam flow equations and numerical simulation techniques is shown to be the key for uniquely defining the empirical foam model parameters and for preserving consistency with simulations of foam flow processes.
An Innovative Approach to Model Two-Phase Flowback of Shale Gas Wells with Complex Fracture Networks
Authors: Yang Ruiyue , Huang Zhongwei , Li Gensheng , Yu Wei , Sepehrnoori Kamy , Tian Shouceng , Song Xianzhi , Sheng Mao
Published: September 2016

Two-phase flow has generally been of more concern in the hydraulic treatment design of shale gas reservoir, especially, during the flowback period. Investigating the gas and water production data is important to evaluate the stimulation effectiveness. We develop a semianalytical model for multi-fractured horizontal wells by incorporating the two-phase flow in both matrix and fracture of the shale-gas wells. We employ the node-analysis approach to discretize the complex fracture networks into a given number of fracture segments, depending on the complexity of fracture system. The two-phase flow is incorporated by iteratively correcting the relative permeability to gas and water phase and capillary pressure for each fracture segment with the fracture depletion. The model is validated by numerical model and field observation. A good match between them was obtained. Then, the early-time gas and water production performance is analyzed using various fracture properties and geometries. A systematic type curves are obtained with the fracture system from simple to complex geometries. The flow regimes that were identified could assist in constraining the fracture geometry and complexity. Additionally, the gas and water decline rates highly depend on the fracture properties such as initial gas saturation in fractures, fracture conductivity, fracture spacing, fracture geometry and connections with natural fracture networks. The improved network fracture conductivity and complexity especially the connections between hydraulic fracture and natural fractures can enhance the gas production and shorten the dewatering time, illustrating that the effective stimulation could facilitate the fractures to clean up more quickly. The gas/water supply from natural fractures and their flow dynamics controlled by two-phase relative permeability effects could be the major reasons for the formation of "V-shape" behavior on the plot of gas/ water ratio vs. cumulative gas production. This work, for the first time, extends the semianalytical model from single-phase flow to two-phase flow in shale gas reservoir with complex fracture networks. The method is simple and gridless, but is capable of capturing the complex fracture system and gas/water transport mechanisms. Also, it provides an efficient technique to evaluate the hydraulic fracture treatment design in multi-fractured horizontal wells for shale gas reservoirs at early production times.
Turning Data into Knowledge: Data-Driven Surveillance and Optimization in Mature Fields
Authors: Temizel Cenk , Aktas Sinem , Kirmaci Harnn , Susuz Onur , Zhu Ying , Balaji Karthik , Ranjith Rahul , Tahir Sofiane , Aminzadeh Fred , Yegin Cengiz
Published: September 2016

Decision making in the oilfield is a crucial process in petroleum oilfield activities where numerous attributes and uncertainties exist in the complete process. In the development process of new fields, a well-organized historical database to minimize uncertainty is important as it decreases risks, provides better insight and robustness in decision making.

Statistics is a strong tool to turn information or data into knowledge when used with care and physical understanding of the cause-effect relation between the attributes and the outcome. Unfortunately, historical data and learnings from the past cannot be used in an efficient way in oilfield decisions due to lack of systematically organized historical data where there is a huge potential of turning terrabytes of data into knowledge and understanding, for more successful decisions and results. On the other hand, using historical data on reservoir enginnering studies are generally very complex since it requires integration of vast amount data from several diciplines that have different data sources and from different scales, which is sometimes leading modelers to prefer new data collections from the field rather than using complex historical data on hand.

In this sense, a multi-attribute based statistical model for each reservoir will greatly enhance the outcomes of future actions through bringing a statistical understanding to a physically more complex relation between the causes and effects or in other words, attributes and results. The data driven models are established for the desired phenomena by means of collecting relevant historical data, after which a multivariate regression is carried out to show the significance of each attribute in the model. These statistical models are then used to make future decisions in the same reservoir in such a way that attributes can be selected within the optimum ranges that yield best results and outcome. Attributes can consist of events and key parameters that influence the outcome.

The model is illustrated to investigate the factor affecting the performance of vertical and horizontal wells in tight reservoirs. The data-driven model is validated with the numerical reservoir simulation model and used to determine the significance of each parameter and the optimum operating intervals.
Injection Induced Fracture Propagation and Stress Reorientation in Waterflooded Reservoirs
Authors: Bhardwaj Prateek , Hwang Jongsoo , Manchanda Ripudaman , Sharma Mukul M.
Published: September 2016

It is now well established that poro-thermo-elastic effects substantially change the magnitude and orientation of in-situ stresses. Fractures induced in injectors during water injection for waterflooding or produced water disposal have a profound impact on waterflooding performance. These effects, coupled with injectivity decline due to plugging caused by injected particles, lead to permeability reduction, fracture initiation and propagation. Models are available for fracture propagation in single injection wells and single layered reservoirs that account for these effects. However, the impact of fluid injection and production on fracture growth in multiple wells and multi-layered reservoirs with competing fractures has not been systematically modelled at a field scale.

In this work, a three-dimensional, two-phase flow simulator with iteratively coupled geomechanics has been developed and applied to model the dynamic growth of injection-induced fractures. The model is based on a finite volume implementation of the cohesive zone model for arbitrary fracture propagation coupled with two-phase flow. A dynamic filtration model for permeability reduction is employed on the fracture faces to incorporate effects of internal damage and external filter cake build-up due to the injection of suspended solids and oil droplets. All physical phenomena are solved in a single framework designed for multi-well, field-scale simulation.

The pressure distribution, saturation profile, thermal front, mechanical displacements and reservoir stresses are computed as fluids are injected and produced from the reservoir. Simulation results are discussed with single as well as multiple fractures propagating. Stress reorientation due to poroelastic, thermoelastic and mechanical effects is examined for the simulated cases. The orientation of the fractures is controlled primarily by the orientation of the stresses, which in turn depends on the pattern of wells and the rates of injection and production. The sweep efficiency of the waterflood is found to be impacted by the rate of growth of injection-induced fractures. Heterogeneities in multi-layered reservoirs strongly govern the expected vertical sweep and fluid distribution, which impacts the cumulative oil recovery.

This is the first time a formulation of multiphase flow in the reservoir has been coupled with dynamic fracture propagation in multiple wells induced by solids plugging while including poro-thermo-elasticity at the reservoir scale. The model developed in this work can be used to simulate multiple water injection induced fractures, determine the reoriented stress state to optimize the location of infill wells and adjust injection well patterns to maximize reservoir sweep.
Integrated Analysis of Reservoir Architecture and Time-Lapse Seismic for Remaining Oil Prediction: A Lithologic Reservoir in Pearl River Mouth Basin, China
Authors: Yu Lin , Yun Ling , Jianming Guo , Xiaomin Zhang , Feng Zhang , Yaonan Li
Published: September 2016

Lithologic reservoirs are characterized by subtle locations and complex architectures. Conventional structure and deposition interpretations based on seismic and logging data are beneficial to the distribution forecast of lithologic reservoirs. But they are not enough to predict remaining oil in the late development stage. A new fine remaining oil prediction method of lithologic reservoir based on the integration analysis of reservoir architecture and time-lapse (4D) seismic is proposed and applied successfully to Reservoir H11.

H11 is a complex delta lithologic reservoir in the Pearly River Mouth Basin. By the end of 2014, its water cut has been up to 98.5%, but EOR is only 35.1%. It is urgency to study remaining oil distribution. There are three key techniques involved, including the dynamic interpretation of reservoir depositional evolutions, fine characterization of sand body architectures & flow barrier distributions and the analysis of 4D seismic difference.

Firstly, constrained by sequence frameworks, stratal slices between the top and base of H11 are extracted at 1ms interval and calibrated with logging. These slices are relatively isochronous and contain the depositional information. According to seismic sedimentology theory, integral interpretations of slices and log facies are used to study spatial evolutions and distributions of H11. Secondly, based on investigations of delta front deposits cropping out in the Ordos Basin, sand body contacts are understood. These contacts are further analogized by core, logging, 3D seismic and acoustic impendence data in subsurface. Whether the contact boundaries are seepage flow barriers is further distinguished through the analysis of development performances or pre-stack inversion data. Finally, remaining oil of H11 was successfully delineated by 4D seismic analysis. The 4D difference data shows significant water movement from the north and west. The presence of bypassed pay at the southern and eastern scattered areas is obvious. Based on these understandings, a proposed well is completed at the southern prediction area in the late 2014 and the result is consistent with the 4D response. Currently, the oil production of this well is up to 2800 barrels per day.

Besides the imperfect well pattern, the complex contacts and lithologic flow barriers among sand bodies are the other reasons leading to the subtle 4D seismic difference. The static reservoir architecture analysis and 4D seismic difference analysis are integrated to improve the precision of remaining oil prediction of H11. This method has been popularized to other lithologic reservoirs of the Pearl River Mouth Basin, and enriches the approach and technique of remaining oil delineation.
First-Time Application of Catenary Concentric Coiled Tubing and Vacuuming Technology
Authors: Choo Der Jiun , Kothari Nikita , Larke James
Published: September 2016

An operator needed to perform wellbore intervention on four low-bottomhole-pressure offshore wells in Malaysia. High sand production was consistent in all the wells, precluding access to the producing zones in the lower completion. The wells had been shut in since 2011, and previous cleanouts using conventional coiled tubing (CT) and nitrogen had been unsuccessful.

The job had to be performed from a work barge in a catenary style, meaning that the injector head, blowout preventers, and power pack were on the platform, but all were operated from a barge. The advanced wireless catenary unit made it possible to complete the operation with only the CT and three flexible lines connecting the barge and the vessel. Due to the nature of the concentric coiled tubing (CCT)—designed to flow returns back to surface—all returns had to be routed away from the platform and onto the barge.

After an analysis and planning session, the operator and the service provider decided to use a CCT cleanout system with a switchable jet-pump designed to remove solids and liquids from ultralow pressure wellbores that are not treatable with standard circulating methods. The operational plan also called for building a specialized CT connector that would enable conventional operations, such as fishing and sleeve manipulation with CCT.

This was the first time that vacuuming technology and catenary CCT were used together to perform a cleanout operation. The results were impressive as extensive amount of sand was removed from the wellbores to surpass target production by 185%. This paper will focus on a campaign in the South Furious field of Sabah, Malaysia in which both the logistic and operational challenges were successfully overcome with 112 days of incident free operations.
Unlocking the Potential of Marginal Reservoirs in Kuwait Through the Application of Optimized Hydraulic Fracturing Technologies
Authors: Al-Othman M. R. , Buhamad A. A. , Al-Houti N. B. , Ashkanani M. S. , Al-Mehanna H. S. , Al-Haddad M. N. , Al-Dhafiri A. A. , Al-Harbi S. M. , Al-Ibrahim A. A. , Al-Zuwayed A. M. , Ahmed A. M. , Al-Dousari M. A.
Published: September 2016

In Kuwait, drilling and deployment plans focus mainly on drilling vertical wells through a wide range of reservoirs consisting of high- and low-permeability sandstones and carbonates, with varying crude types from medium-heavy to condensate. Since 1935, Kuwait has produced mainly from the types of reservoirs that keep its daily production as high as possible to accommodate the country's economic needs. With the aging of these mature reservoirs, reservoir pressure reduction and water production become a major challenge, in addition to the limited access to drilling resources. Accordingly, exploring different reservoirs and unlocking the potential of the existing low- to mid-permeability reservoirs through advanced fracturing technologies are considered the alternative plan to compensate for production decreases and to improve oil production. However, implementing such technologies requires a customized design and candidate selection process.

The plan involved a multidisciplinary well candidate screening and selection criteria for different reservoirs and fields. The criteria include different parameters such as bubblepoint pressure, minimum formation thickness, and rock mineralogy, in addition to the study of the previously applied production enhancement technologies. About 50 wells have been selected from different reservoirs and fields across Kuwait for the initial pilot plan to evaluate the potential of a wide range of reservoirs. Then, a customized fracturing technology design followed that included operational planning, execution, and evaluation.

Approximately 20 fracturing treatments were executed successfully, and the post-job evaluation showed two- to four fold gains in production. This changed the development strategy and allowed for further development plans for these reservoirs. These newer plans included the application of technologies such as channel fracturing for proppant fracturing and fiber-laden self-diverting acid system for acid treatments.

The well candidate selection criteria and customized design of channel fracturing technology for the sandstone reservoirs and fiber-laden self-diverting acid system technology for fractured carbonate reservoirs resulted in a total additional gain of approximately 15,000 B/D. The detailed engineering design from candidate selection to treatment and the application of optimized hydraulic fracturing technologies enabled production enhancement and additional recoverable reserves from the most challenging low-permeability and low-API gravity candidates for the first time in Kuwait where conventional stimulation techniques were not providing the expected results.
New Algorithm to Quantify Productivity of Fishbone Type Multilateral Gas Well
Authors: Ahmed Musa Eltayeb , Alnuaim Sami , Abdulazeem A.
Published: September 2016

Due to the increase of global gas demand and the evolution of tight and shale gas development, thousands of multilateral gas wells have been drilled in the last decades. A multilateral well is defined, in general as a well with multiple branches in the lower borehole targeting oil and gas reserves in the same or different strata. These branches are called laterals. Multilateral wells with the laterals drilled out from the main horizontal wellbores at the same elevation are called fishbone wells. Multi branched wells are very effective in many different aspects such as reducing the development cost, improving sweep efficiency and maximizing recovery in oil and gas reservoirs. In this paper, a new empirical algorithm to quantify the productivity of fishbone type multilateral dry gas well is proposed. A reservoir commercial simulator was used to simulate the gas flow through a multilateral dry fishbone type gas well. Different well and reservoir parameters such as number of laterals, permeability ration (kh/kv), length of lateral sand lateral spacing have been changed and their effects on the well Inflow Performance Relationship (IPR) were evaluated and incorporated into the new IPR model. It was found that the IPR curves are strong function of the number of well laterals (n), the permeability variation and lateral length. Statistical software was used to perform nonlinear regression and generate a new empirical IPR correlation of Vogel-form to describe the productivity and well performance of a fishbone type multilateral dry gas well. Finally, detailed model verification was done through a comparison of data generated with the new empirical correlation and data generated from a commercial well performance software using real field data with acceptable match.
Technology Driven Rejuvenation of a Mature Field by Doubling the Gross Production Rate
Authors: Giden I. , Kometer B. , Toth P. , Geier H. , Florian T. , Sieberer M.
Published: September 2016

The 16. Tortonian Horizon is one of the largest producing oil reservoirs in continental Europe. The field has been on production since 1949 and has already gone through a long decline period. The average water cut currently exceeds 96%. The western region of this reservoir, called Bockfliess area, was the focus of the latest field re-development effort, aiming to increase oil production by doubling the liquid rate.

Although the project comprised various activities – including facility upgrades and the construction of additional surface infrastructure –, this paper focuses mainly on subsurface measures. The majority of modifications were conducted on existing production wells. Quick wins included additional perforations and sucker rod pump (SRP) unit changes. The artificial lift systems of more than one third of the producers were converted to electrical submersible pumps (ESPs). Three new high-rate horizontal producers were also drilled. To maintain reservoir pressure, nearly all the produced water had to be re-injected. Several of the existing producers were converted to injectors and two new horizontal injector wells were drilled.

The overall goal of doubling the gross production rate was accomplished by an integrated multidisciplinary team in a short time period. 13 additional perforations, four SRP unit exchanges and 32 conversions of producers to ESPs proved to be successful in increasing oil production.

In order to target the remaining attic oil, three high rate horizontal infill producers were effectively placed within specific zones of the reservoir by applying state of the art geosteering technology. The planned voidage replacement ratio was achieved by converting nine producers to injectors and two successfully placed horizontal high rate injector wells. These measures increased oil production by 62% (43% was gained from existing wells and 19% from new wells).

The concept of doubling the gross rate on a reservoir scale was unprecedented in Austria, especially for a reservoir that was already producing at maximum surface capacity. For single wells, gross rates were increased up to seven-fold as compared to the rates produced before the project. To control such high volumes with an optimized operation, real-time monitoring of the sensor-equipped ESPs was implemented. Horizontal infill drilling had not been implemented before in the targeted reservoir area due to the close well spacing. Real time geosteering methods using advanced logging while drilling (LWD) technology proved to be beneficial in this onshore mature brown field. Different sand control and bottom hole flowing pressure control methods were applied in each of the new horizontal producers, including autonomous inflow control devices (AICD) which are currently mainly utilized in offshore environments.
Technology Trial Review: Selective Coiled Tubing Re-Entry of Seven-Lateral Openhole Well Using Electromechanical Arm
Authors: Abdelaziz Mohannad , Ahmad Talha , Saeed Abubaker , Zarea Marwan , Busfar Wessam , Sagr Hani
Published: September 2016

The number of MRC (Maximum Reservoir Contact) wells has increased significantly since they were first introduced in 2002. Most of these wells use multilateral well configuration to increase the contact with the reservoir and therefore the well productivity. (Salam Phillip Salamy, 2007)

One of the main challenges for multilateral wells is the selective accessibility of the well during the production phase to perform various rig-less activities (such as stimulation, production logging, water shut-off… etc.). This requires detection and confirmation of lateral window depth and orientation and means to allow the tool to be selectively steered into the desired lateral.

From all multilateral well configurations classified by TAML (Technology Advancement of Multi-Laterals), Level-1 (openhole mainbore and lateral) is considered the most difficult to re-enter. This is caused by the fact that the shape and quality of the wellbore near the junction is highly unpredictable after the early lateral window construction and the later distortion by the flow of hydrocarbons. Since both the mainbore and laterals are openhole, the simple metal dependent logging tools (such as CCL: casing collar locator) cannot be used as a way to confirm the successful entry of the openhole lateral as in Level-2 TAML (cased mainbore).

Well Lateral Intervention Tool has been jointly developed to address this issue. The tool has two main sensory packages (ultrasound and magnetic) to obtain the lateral details (depth and orientation) and an electromechanical arm that can be actuated with different angles to guide the BHA inside the required lateral. This paper presents the challenges and outcomes of the tool field trial in a Level-1 multilateral well. The oil producer candidate has an openhole mainbore and six openhole laterals branching from it (fishbone well). The tool has been successfully used to guide PLT (Production Logging Tool) into three of the six laterals limited only by Coiled Tubing reach.
Successful Managed Pressure Cementing With Hydraulic Simulations Verification in a Narrow Pore-Frac Pressure Window Using Managed Pressure Drilling in Saudi Arabia
Authors: Siddiqi Faizan Ahmed , Riskiawan Arris , Al-Yami Abdullah , Elmarsafawi Youssef , Jain Bipin , Louati Issam , Martanto Roni , Taoutaou Salim
Published: September 2016

Managed pressure operations enable keeping the equivalent circulation density (ECD) within a narrow pore-frac pressure window during drilling and cementing while maintaining the wellbore stability and controlling formation pressures. The operation becomes more complex during a cementing job, where fluids with different density and rheology parameters are pumped downhole at varying rates, resulting in different friction pressure profiles. Proper numerical simulators must be used to model such variations and keep the downhole pressure between the pore and fracture pressures during the operation.

Managed pressure techniques and technology were critical to the successful cementation of the 7-in. liner at 12,000 ft. in a gas field in Saudi Arabia, across formations ranging from a high-pressure zone with 2.36 SG (19.65 ppg) formation pore pressure to a depleted low-pressure formation with 2.44 SG (20.32 ppg) fracture pressure. The challenge in this job was to maintain the ECD at 2.40 SG (20 ppg) throughout the cement job to avoid any losses or flow from the formations.

An automatic choke setup on the return flow line with a dynamic control system was used to drill the 8.375-in. open hole with KCl polymer mud. Precise cementing simulation was used to determine the ECD during cement placement. Numerous pre-calculations and simulations were run to evaluate various scenarios prior to the cement job to ensure effective manipulation of back pressure through managed pressure drilling (MPD) equipment to maintain ECD at the desired value throughout the cementation process.

The detailed simulations run by cementing and MPD engineers prior to the job and a collaborative approach were instrumental in defining a final cementing plan, completing the layout of equipment used for the cementing job, and executing the job with real-time monitoring of all critical parameters affecting ECD and evaluation of the cement job.
Computer Modeling for Intelligent Control of Gas-Condensate Reservoir
Authors: Mikolajczak Edyta
Published: September 2016

Smart wells combine monitoring and control technology. These smart completions are equipped with sensors to monitor well and reservoir conditions, and valves to control the inflow of fluids from the reservoir to the well. However, this intelligent equipment is located only in the downhole.

The idea of this paper is to create virtual sensors located in different parts of the reservoir, which will be used to intelligent production control. This work explores a new algorithm for smart control of the gas-condensate reservoir. The proposed algorithm uses the analogies to a greedy algorithm as well as known natural intelligent structures like biological systems. The aim of this paper is to find an optimal well management strategy over the assumed life of reservoir.

Gas-condensate reservoirs have a reservoir temperature located between the critical point and the cricondentherm on the reservoir fluid's pressure-temperature diagram. If bottomhole flowing pressure is less than dew point pressure, then vapour and liquid phases drop out in the porous media around the production well restricting the flow of gas. The near-well chocking can reduce the productivity of a well.

Moreover, one of the goals of this paper is developing intelligent production scenarios for gas-condensate reservoir. The computer simulation has been carried out in the ECLIPSE reservoir simulator and the virtual sensors have been located within the reservoir. The actions programmed according to virtual sensors measurements yield self-modifying strategy of reservoir control. The proposed algorithm analyses reservoir behavior and changes production strategy in each time step to control the condensate bank range and, as a result maximizes the net present value (NPV).

This paper presents a brief description of the created reservoir model and detailed explanation of the proposed algorithm. The next part focuses on the obtained results which indicate that this algorithm ensures intelligent control of gas-condensate reservoir and therefore the most profitable production scenario.
Unconventional Reservoir Perforating Cluster Spacing Optimization Method for Staged-Fracturing Horizontal Well
Authors: Lu Qianli
Published: September 2016

Multi-cluster staged fracturing is an effective method to exploit shale gas. Field observations reported some clusters did not generate fractures. X5 formation in Sichuan Basin is a 3000m deep shale reservoir. The horizontal stress difference is so high, therefore it is difficult to generate fracture network. How to enable all fractures propagate effectively from each cluster and generate enough stress interference to enable fracture network is of critical concern.

This paper established a 3D fracture propagation model based on finite-element method to simulate multi-cluster fracturing of X5 reservoir. The fracture propagation model couples seepage-stress-damage theories to simulate fracture propagation. The cohesive element is used to simulate the forming of fracture, and the filtration from fracture to matrix is taken into consideration. This model is used to study three fractures propagating simultaneously from three clusters. Six different cluster spacing cases were simulated to investigate the fracture geometry and the stress field.

The research finds that when the cluster spacing is 10m, 20m, 30m and 35m, the length of the middle fracture is severely restricted; but for the side fractures, the length is over propagated. When the cluster spacing is 40m and 50m, balanced propagation of all the three fractures is achieved. In the 10m, 20m, 30m, 35m and 40m cluster spacing cases, the horizontal stress ratio is low and could generate fracture network, but the 50m case could not. By considering the fracture geometry and stress ratio, the optimized cluster spacing is 35m-40m. Based on this optimization, a 7-stage fracturing treatment of X55 well was designed and conducted. The treatment process was smooth and its production was 1.7 times the average production of the adjacent horizontal wells.

This paper presented a method to optimize the cluster spacing by both considering the fracture geometry and stress ratio. Cluster spacing optimized by this method could enable the effective propagation of all main fractures and increase the possibility of generating fracture network.
Advanced Production Data Analysis in Oil Carbonate Reservoirs
Authors: Adrian P. M.
Published: September 2016

In recent years there has been an increasing interest in the use of Advanced Production Data Analysis (APDA) methods for dynamic reservoir description. These methods analyze available daily production data, reducing Well Testing operations cost and avoiding production loss, with accuracy comparable to Pressure Transient Analysis (PTA). Different models have been proposed for homogeneous, coalbed methane and shale gas reservoirs. Unfortunately, carbonate reservoirs production are still being analyzed with homogeneous models.

This work presents the analytical derivation of two Advanced Production Data Analysis methods (Dynamic Material Balance and Blasingame Type Curves) based on the dual porosity model, to analyze daily production of Oil Carbonate reservoirs. Pseudosteady-state and transient (slabs and spheres) interporosity flow between matrix and fractures were considered.

The development was based on long-time approximate solutions of diffusivity equation in dual porosity system, for constant flow rate in a closed system with no-flow boundary. They were compared to exact solution in Laplace Space using Gaver-Stehfest algorithm. Then applying the appropriate dimensionless definition, both APDA methods were derived, including the generation of type curves. The validation was made using synthetic data generated by a numerical simulator for constant and variable flow rate.

Results confirm the applicability of current APDA methods basd on homogeneous reservoirs, for the cases of transient interporosity flow between matrix and fracture. Nevertheless, additional considerations must be taken into account in the case of pseudosteady-state interporosity flow.
Development of Centrifugal Downhole Oil/Water Separator: Simulation and Experimental Study
Authors: Hashem Mohamed Hossni
Published: September 2016

In the shadow of low oil prices, it is necessary to develop economically and environmentally friendly solutions. In oil and gas industry, majority of the production stream is water. This water is produced with the hydrocarbon to surface. This requires the separation of the fluids produced and then treating those streams to abide with environmental regulations and clients' specifications. CDOWS (Centrifugal Downhole Oil Water Separator) technology is believed to provide high separation quality, high oil recovery with reduction of operating costs and less surface facilities.

The development process involves simulation of tubular centrifuge using a computational fluid dynamics (CFD) software to analyze the parameters affecting separation. After that, an experimental set up is erected which mimics in-well CDOWS. The novel design of the tool involves specially designed weir to collect the oil and water through concentric tube configuration. The parameters tested through simulation include; flow rate, RPM, tubing length, tubing diameter, API and oil/water ratios. The experimental set-up is used to confirm the sepration in the rotating tube as it is made of acrylic material.

The CFD model involves a rotating cylinder (tubing) in which oil and water are introduced from the inlet. The feed of oil and water exhibits high centrifugal forces resulting in their separation through and to the outlet of the tubing. The experimental design mimics the actual in-well design which can be implemented in a well. The design can be configured easily to change the tubing parameters.

After conducting the studies, a sensitivity analysis using design of experiment approach (DOE) and response surface plots is produced to emphasize on parameters and their interaction effects.

Findings include better separation using higher RPM, ID, L, water salinity, API. The most influential factor is RPM which can be controlled and thus will define costs for later stages of the project.

This paper presents the first work on CDOWS which is analogous to in-well configuration aiming for a solution with reduced costs.
Reducing Freshwater Consumption in the Marcellus Shale Play by Recycling Flowback With Acid Mine Drainage
Authors: Cavazza Michael
Published: September 2016

Acid mine drainage (AMD), the largest source of stream pollution in the state of Pennsylvania, has the potential to be utilized as a make-up fluid for hydraulic fracturing in the Marcellus shale. Abandoned coal mines across the state are responsible for discharging AMD into nearby streams, imairing local ecosystems. If AMD could be used in hydraulic fracturing operations, gas companies can be responsible for a cleaner environment in Pennsylvania. To use AMD in hydraulic fracturing, the high sulfate (SO42-) concentration must be reduced (<100 mg/L). If not, there is a risk of scale formation in the wellbore.

Sulfate concentrations can be reduced by mixing AMD with flowback, which has high concentrations of barium (Ba2+) and strontium (Sr2+). Sulfate will react with the barium and strontium to precipitate barite (BaSO4) and celestite (SrSO4) which can be removed from the fluid. The challenge is determining mix ratios of the two fluids, AMD and flowback, to reduce these three constituents to acceptable levels. Both AMD discharges and flowback vary from location to location making this challenge a difficult one.

For this study four coal mine discharges and two wells located in southwestern Pennsylvania were sampled. These samples were mixed at various ratios to determine removal efficiencies and kinetics for sulfate, barium and strontium precipitation. Ideally, these reactions would occur quickly and result in a fluid free of sulfate, barium and strontium. The mixing tests showed that barium and sulfate could be removed to acceptable levels, while strontium could only be removed by a maximum of 50%. X-ray diffraction (XRD) analysis concluded that celestite does not form when the fluids are mixed, rather strontium co-precipitates with barium. Kinetic tests showed that precipitation reactions occur quickly, within one day of mixing and no further reactions occurred.
Simulation Opportunity Index, A Simple and Effective Method to Boost the Hydrocarbon Recovery
Authors: Saputra Wardana
Published: September 2016

During periods of low oil prices, profitability of field developments drops drastically. To help with this difficulty, a cost-effective method has been proposed to boost the hydrocarbon recovery by optimizing well locations through the Simulated Opportunity Index (SOI). SOI is an intelligent method to identify zones with high potential for production which is empirically calculated from basic rock and fluid properties, and from reservoir pressure as its energy capacity. In order to obtain the best results, the original SOI formula (Molina et al., 2009) was extended to both oil and gas fields. Based on this modified SOI formula, a software program has been developed to locate the best well locations considering multilayer, existing wells, and fault existences.

This paper describes how the SOI software helps as a simple, fast, and accurate way to obtain the higher hydrocarbon production than that of trial-error method and previous studies in two different fields located in offshore Indonesia. On one hand, the proposed method could save money by minimizing the required number of wells. On the other hand, it could maximize profit by maximizing recovery.
Wave Propagation Models Capture Pressure Behavior in Heterogeneous Unconventional Reservoirs
Authors: Li Hanyu
Published: September 2016

Estimating ultimate recovery using information from the boundary-dominated flow regime is not practically achievable in unconventional (low permeability) resources since the time required to reach this flow regime is quite large (typically years). In response to this problem, the ultimate objective of this research project is to estimate ultimate recovery of horizontal wells with multistage fractures using only information obtained after wells have reached interference between adjacent fractures. I have taken the first step towards achieving this objective by simulating the boundary condition in heterogeneous reservoirs using the similarity between pressure diffusion and electromagnetic and ray wave propagation. Estimating ultimate recovery more accurately will enable us to optimize well spacing and reduce the number of unnecessary wells drilled, saving capital investments of many millions of dollars.

I have implemented the mechanism of electromagnetic and ray wave propagation in pressure diffusion models to simulate boundary conditions that affect flow in the reservoir. When a light wave reaches the interface of two media, some light is reflected back to the same media while the remainder is transmitted into the other media. A ‘pressure wave’ behaves in a similar way when it reaches a boundary in the reservoir. Therefore, we have incorporated reflection and transmission coefficients into the drawdown solution of the diffusivity equation. We used a channel reservoir to validate our approach. The pressure transient analysis solution obtained using our method matches well with the true solution generated by the pressure transient software Ecrin. We can use the accurate early time match to estimate important reservoir properties including porosity and permeability. The accurate middle time pressure information can be transformed into rate information and then used to estimate ultimate recovery.