Because fracture gradient changes with rock type, some formations are more sensitive to induced fractures than others. Depending upon depth, the fractures created will either be horizontal or vertical. If the depth is 2500 feet or less, horizontal fractures are usually produced. Because horizontal fractures require lifting the entire overburden, they are limited to shallow depths. At depths over 3500 feet, fractures are usually vertical. Because vertical fractures occur without lifting the overburden, they can be created at much lower pressure. The propagation pressure is generally much less than the pressure that would be required to initiate the fracture. Consequently, fracture losses, once initiated, are difficult to control. Wellbore instability, particularly in shale formations, is a major challenge in drilling operations. Many factors such as rock properties, in-situ stresses, chemical interactions between shale and drilling fluids, and thermal effects must be taken into consideration in well trajectory designs and drilling fluid formulations to mitigate wellbore instability-related problems. The Steerable Drilling Liner service combines a rotary steerable system with a liner to help overcome the challenges: drilling in zones with lower pressure and unstable shale/coal layers, and with formations of varying flow and pressure regimes. Running the liner while drilling keeps the wellbore stable and eliminates the need to pull the drillstring to run casing. This is how it reduces your risks and NPT, saving the costs associated with contingency plans. Because the liner is isolated from the reamer shoe, you can rotate the liner at much lower RPMs than the pilot and reamer bits. This design lessens the load on the liner, improving its fatigue life. The Steerable Drilling Liner steerable drilling liner service helps you to mitigate the risk of hole collapse and formation damage by reducing openhole exposure, Reduce NPT by eliminating extra trips and ensuring that the liner is installed at TD from the first run Enhance wellbore integrity by drilling with the liner, leading to the plastering effect, which reduces fluid loss and cuttings volume, Lower health, safety, and environmental (HSE) risks by reducing pipe handling and rigsite footprint size Steerable Drilling Liner service developed and qualified using a rigorous processes including extensive onshore testing at the service provider Experimental Test Area (BETA) facility before being successfully deployed offshore. Rely on Steerable Drilling Liner service performance in extreme environments; the cost-effective Steerable Drilling Liner service promotes wellbore stability and performs reliably in the challenging downhole environments. This Paper will reveal the technology overview, updates, case histories and field limitations

In The Netherlands the operator drilling in the Southern North Sea area had to drill through Germanic Trias super group sequences to the reservoir sections in Buntsandstein formations of lower Triassic series at a depth of about 9,800-ft TVD that are highly abrasive and hard sandstone formations. These formations are overlaid by middle and upper Triassic clay stones interbedded with hard dolomite stringers. The compressive strength of these formations ranges from 5,000–15,000 psi in the upper clay stones and from 15,000–30,000 psi in the Buntsandstein group. Drilling the build and turn wellbore profiles using a directional BHA with roller cone and/or PDC has been challenging. In offsets, these bit types produced slow ROP and short run lengths, requiring multiple bit trips to complete the hole section. In many cases, the bits were pulled in poor dull condition with severe cutting structure damage. In some cases, the operator was forced to use diamond-impregnated bits on turbine to TD the section. To drill the section in one run and at higher ROP, the provider recommended a new-style conical diamond element bit that uses multiple conical shaped diamond elements (CDEs) positioned from bit center to gauge. The CDE's conical shape penetrates high-compressive-strength rock with a concentrated point loading that fails formation with a plowing mechanism. Design engineers used a finite-element-analysis (FEA)-based modeling system to strategically place the CDEs based on specific drilling parameters and formation characteristics. Recent R&D tests confirm the hybrid PDC bit drills with 25% less torque compared with conventional PDC cutters, providing increased directional control and smoother toolface response. The result is higher build rates that achieve directional objectives in less time. The new 513 design also included a centrally located CDE to enhance bit stability and mitigate shock and vibration. The bit was run on an RSS BHA and drilled 1,279 ft of difficult claystone and anhydrite/dolomite with silt/sandstone stringers at an average ROP of 31.04 ft/hr, 200% faster compared to the closest offsets in the reservoir sand. The bit also set a new single-run footage benchmark for this section in Block P15. The RSS BHA efficiently delivered all directional wellbore requirements, building inclination from 26° to 39° with a DLS of 3.42°/100 ft and 6.09°/100 ft in Sidetrack 1. As a result, the operator saved one day of rig time and a bit trip for a total savings of approximately USD 635,000.

This paper describes case-studies of Formation Isolation Valve design, completion options, installations, well bore access for Intelligent Completions and successful replacement of electrical submersible pump (ESP). These completions are installed for production optimization in multilateral and horizontal wells. ESP completions has a long history in oil field and intelligent completions have been nearly stared 15years back. Isolation Valves have been installing for over 20 years and more than 2000 wells have been successfully completed. In few wells upper completions have been successfully recompleted with ESP. The technology has provided real value in these ESP wells and also in intelligent completions wells. There are several measures such replacement of underperforming ESP systems, sidetracks in more prolific zones and upsizing of the pumps have been taken. The formation isolation valves were used with ESP completion to protect reservoir formation from drilling and work over fluids during replacement of pump. This saves fluid cost, rig time, reduce rig cost, avoid formation damage and improve productivity. Few benefits are below: Allows multiple pump replacements without killing the well Isolates formations without applying kill fluid to the formation Reduces fluid losses during completion installations Improves well productivity by preventing formation damage Reduces costs associated with well interventions ESP systems with formation isolation valve are delivering the industry the solution to achieve production targets while protecting reservoir damage due to kill fluid during work over operations for pump replacement and at the same time allowing access to mother bore for stimulation and logging in ESP and Intelligent Completions.

Mud loggers are the first (and sadly in some cases the only) people to look at the cuttings. To actually see what the rocks look like, feel like, occasionally even taste. Most people looking at a well will actually look at “wriggly lines” or at best the cuttings descriptions from the loggers or geologist, two or three lines of abbreviations “claystone, light grey to grey, soft to firm, occasionally hard, slightly calcareous, trace fine sand”. We have all read them, many of us have written them. These descriptions are incredibly useful and valuable, they are often all we have to understand the actual rocks and geology, especially with older wells. But in a world where we now enter the description and draw the logs with a computer, this information still comes from the subjective view of the logging geologist peering through a microscope In recent years, several tools have been developed to analyze drill cuttings from oil and gas wells. The most commonly used tools include X-ray fluorescence (XRF), X-ray diffraction (XRD), scanning electron microscopy (SEM) combined with energy dispersive X-ray spectroscopy (EDX), bulk density, and pyrolysis. Although each of these tools can be used to develop a limited determination of the in-situ rock character, the combination of three of these tools (XRF, SEM/EDX, and pyrolysis) can provide a more comprehensive picture of formation properties. The combination of XRF analysis with the SEM/EDX analysis is the key to the cuttings workflow. The exact location within the borehole can be determined and a robust mineralogy developed that is independent of normative mineralogy (typical XRF) or operator-interpretive mineralogy (XRD). Additional outputs include relative brittleness index, bulk density, lithology, fractional and textural relationships, total organic carbon (TOC) proxy, and a new porosity index. Trace and major elemental ratios are also available for precise stratigraphic placement. The addition of cuttings pyrolysis enables hydrocarbon typing, producible hydrocarbons, TOC, and total inorganic carbon (TIC) within each sample to be established. Chemical Lithostratigraphy uses whole rock inorganic geochemical (elemental) data, to give information on: Extrabasinal source area dominance and origin (volcanic, metamorphics, igneous, sedimentary), Extrabasinal component weathering or diagenesis (cementation) Intrabasinal components (Palaeo-environment and insitu origin of sediments) Chemical Lithostratigraphy analysis of cuttings can be done either in the laboratory or at the rig site using technology advanced Surface Logging Services (SLS) that includes both XRF and XRD equipment, in additions to SEM and Pyrolysis. Where an appropriate protocols uses for cuttings fraction that are most depth representative With the growing interest in hydraulically fracturing reservoirs both in main land USA and now globally, there has been a growing need to better characterize the reservoir to maximize hydrocarbon recovery while also reducing the overall cost in the recovery of the hydrocarbon. With current fracc-ing regimes relying on a large number of stages to ensure maximum recovery, which in many cases leads to upwards of 30% of these stages being unproductive. This reduces the overall profitability of the well even with maximum hydrocarbon recovery. With the ongoing development of automated mineralogy tools, such as the RoqSCAN, there is now the ability to characterize a reservoir at the well-site in real-time and also rapidly in a laboratory. In this paper we will review the current development of these mobile and ruggedized instruments using a real life project for Eagleridge Energy LLC, on their Burgess lateral well. The paper will show the application of automated mineralogical analysis of cuttings samples pre-drilling in defining stratigratic zones via mineralogy/elemental data. And then explore the application of the same data to assist, and in this case lead, the decision making process during directional drilling of the lateral well. The paper will also look at the use of the technology in defining tactical fracc-ing zone based on rock properties (e.g. ductility) determined from the mineralogical, elemental and textural data. This paper will show that through the use of automated mineralogical instruments, companies can pro-actively steer wells by identifying mineral changes within lateral borehole, indicating a deviation from the target zone. Additionally, this type of technology can be used to reactively steer by its ability to rapidly identification subsurface changes, such as unknown (undetected) faults. Finally the paper will show that through the better characterization of this reservoir companies can reduce the risk associated with the drilling of expensive lateral wells.

Oil and Gas companies are always concerned with continuously evaluating reserves of their assets. Calculating reserves is not an easy task since it requires full knowledge of many technical and non-technical aspects regarding the reservoir nature, available budget, utilized technology, economical conditions and others. Generally, the most important parameter in calculating the reserve for new fields/reservoirs is the “Recovery Factor”. Therefore, many technical approaches available to estimate hydrocarbon reserves are related to estimation of recovery factor. Recovery factor considers all the aforementioned technical and non-technical aspects. And because these aspects can be numerous, with some that can be only quantified subjectively, the first step in our approach was to standardize and normalize many of these aspects in order to formulate them into digital values to be used in Neural Network algorithms. We gathered all those aspects and classified them into two main categories: Quantitative parameters and Qualitative parameters. Quantitative parameters are normally available in digits (e.g. permeability, porosity, net-to-gross, reservoir pressure… etc.). Nevertheless, this is not the case in handling the Qualitative parameters since parameters like Technology, Asset Remoteness and reservoir structure complexity are not normally represented in digits. By using wide range of actual fields' data, we had a very good calibration and control points on the algorithm we are going to use. These data include almost all the governing parameters such as Asset Economics, Technology, Facilities, Start of Production, Number of Wells, Reservoir Architecture, Rock and Fluid Properties, Reservoir Energy and others. Since some of these aspects may be hard to find, we generated two well-trained Artificial Neural Network (ANNs): (1) Simple NN includes a few “easy-to-know” basic data, and (2) Sophisticated NN that includes many advanced data with reasonable accuracy. These NNs were taught with more than 150 lessons at which the inputs (lessons) were the aforementioned “parameters” and the output was the “Recovery Factor”. Testing both the simple and sophisticated networks showed prediction capabilities of 9.5% and 8.0% of actual recovery factor, respectively.

Innovative techniques are highly required in the O&G industry to meet the future demand of the hydrocarbon fuels, significant efforts have been exerted on the development of new innovative technologies to increase the oil recovery. Nanotechnology has provided new promising approaches to enhanced oil recovery (EOR) techniques in old and marginal fields. Nanoparticles have been developed for various applications in reservoir engineering and EOR fields. Using nanoparticles for EOR applications refers to their small size compared to the pore throat sizes; therefore, they could easily move into porous rocks without severe influence on permeability. The applications of nanoparticles to enhance the oil recovery can be summarized in three approaches; Nanocatalysts, Nanoemulsions, and Nanofluids. In this paper, the different possible displacement mechanisms of the nanofluids are discussed.

This paper presents an alternative for operators regarding tools and methods using coiled tubing (CT) during the implementation of horizontal completions. To help address challenges faced developing horizontal completions, both cemented liners and open holes have been widely used in conventional and unconventional reservoirs. Various completion techniques have evolved from traditional tubing conveyed perforation (TCP) and plug setting, and hydrajet assisted fracturing has become the preferred pumpdown technique within the last six years in northern Mexico. The criteria used to determine the completion technique is based on three parameters—extension of horizontal length developed [well geometry, dogleg severity (DLS), deviation], fracture design (pump rate, number of intervals) and type of reservoir being exploited. For the case discussed, a pumpdown technique was selected. Pumpdown techniques are considered one of the fastest completion techniques to provide mechanical isolation between fracture stages; nevertheless, it has not been completely effective during all stages. Some of these techniques can cause premature setting of bridge plugs because of poor sand displacement or adverse well geometries, including high DLS. During the application of this technique, CT interventions are primarily considered in the event of contingencies, such as screenouts (sand cleanout) and plugs prematurely setting (plug millouts). Even though no completion operation is immune to contingencies and associated costs and nonproductive time (NPT), a constant repetition of them because of inherent well conditions or poor fluid admission by the formation increases associated completion costs and diminishes equipment efficiency in place (frac set, logging unit). As a result, CT has become an effective solution with the development of new tools and techniques to avoid such contingencies. This paper develops the concept “plugging and jetting,” wherein a mechanical isolation bridge plug (BP) is placed with CT, allowing abrasive perforations to help the producing formation communicate with the wellbore in a single run, thus allowing reduction of NPT up to 30% and providing a new alternative for horizontal completions. This paper presents case histories with benefits and results. Bottomhole assembly (BHA) design considerations with improvements that provide a new alternative to operators are also presented. This method allows completion of fracturing stages in a continuous manner, thus being advantageous in terms of operational time reduction and consequently cost savings.

Uncertainty quantification is an important task in reservoir simulation studies used for decision making. There have been many techniques proposed in the SPE literature for quantifying uncertainty, such as Markov chain Monte Carlo (MCMC). MCMC is statistical method for sampling from an arbitrary probability distribution to quantifying uncertainty in reservoir simulation. The major difficulty in applying MCMC methods is high computational cost. The purpose of this paper is to demonstrate the performance of a new technique – Multilevel Markov Chain Monte Carlo (MLMCMC) – for quantifying uncertainty in reservoir simulation with less computional cost compared to Standard MCMC. MLMCMC algorithm is based on decomposing the desired results into a set of components calculated with different level of coarsening level. This technique demonstrated a speed up and provided a forecast with no significant loss in accuracy compared to Standard MCMC. It makes Monte Carlo estimation a feasible technique for uncertainty quanti?cation in reservoir simulation applications. There are only a few applications of MLMCMC in the petroleum industry as it is a new technique. We show results for two fields. The first is Teal South in the Gulf of Mexico and the second is Scapa in a North Sea.

Dual-viscosity fluid is a fracturing fluid that has been recently introduced to cover a wide range of fracturing applications varying, from a non-delayed to delayed fluid system for treatments in low to moderate to high temperatures, respectively. Reducing the impact of the pressure effect of traditional borate cross-linked systems, the system crosslinker is compact and delivers a relatively high concentration of crosslinker per unit volume; it is also compatible with current metering pumps, covering a range of treatment rates compared to the current fluid system, and this can simplify logistics on location. The North Bahariya oil fields are onshore fields located in the Western Desert of Egypt and operated by Sahara Oil and Gas Company (SOG). The fields contain proven oil reserves in two sandstone packages at relatively shallow drilling depths (6,500 ft. subsea) in the Abu Roash "G" member (A/R G) of Cenomanian (Cretaceous) age. These sandstones comprise the main reservoirs in the field. During the last 4 years, the introduction of various techniques has led to a fourfold increase in the production from these fields. This success story is mainly the result of using the new hydraulic fracturing methods such as channel fracturing technique and continuous improvement of the fracturing treatments. SOG has been at the forefront in applying novel technologies to optimize the fracturing fluid treatment by using the dual-viscosity fracturing fluid to improve the wells potential. This technology has been implemented in Abrar field. As seen in case studies, very positive results have been seen in both zones of the A/R G formation in terms of improvement in the well performance. Experiences in Abrar field illustrate how to optimize the production rate in a marginal field by optimizing the hydraulic fracturing treatment fluid and how to build on this success for subsequent fields while pushing the innovation envelope further.

The ongoing drilling campaign for an operator drilling in Egypt's Western desert area involved drilling vertical and directional wells approximately 5,000- to 5,500-m deep. The application involved drilling through very hard and abrasive sandstones, and intercalations of shale, sand, silt and dense dolomite inter-beds of about 25,000 psi unconfined compressive strength (UCS). Historically, poly crystalline diamond compact (PDC) drill-bit showed inconsistent bit performance that included premature bit failure and low rate of penetration (ROP), resulting in costly bit trips to the surface. New and improved bit technology was required to improve the penetration rate and footage to reduce bit trips to the surface and improve the overall drilling performance. An in-depth study of the formation properties, wireline logs, drilling parameters and bit dull analysis was performed. Detailed analysis identified this application can benefit from running cutters with a non- planar cutting face on a field-proven seven- blade PDC bit frame. The bit was run on a Rotary Steerable System (RSS) coupled with a positive displacement motor (PDM) on top of the BHA to further improve the drilling efficiency and overcome any challenges. Upon deployment, the 8½-in bit design with the new 16-mm cutters with non-planar cutting structure combined with optimized depth-of-cut control, stability, hydraulics efficiency and balling prevention features led to improved performance when drilling the complex, hook-shaped well profile (where torque and drag were an issue in the past). Compared to field offsets, the bit drilled very smoothly and aided the operator in placing the well in the correct direction with minimum bit- torque caused from bit and formation interaction. Offset bits fail to achieve the required directional plan in the past because of the severe nature of drilling in the area. This integrated solution resulted in a 15% improvement in the ROP as compared to the offsets and a 57% improvement in footage drilled. This performance replaced six drill bits, which were used to drill the same interval in the offset wells. The new innovative PDC cutter technology saved the operator at least USD 250,000 from the planned authority for expenditure (AFE) cost, as well as set two consecutive footage records. This paper outlines the problems in drilling this challenging area, the thought process behind using the various technologies incorporated in the PDC bit design and the keys to overall success.

Carbonate reservoirs have been recognized as very heterogeneous formations due to complex depositional environments, which complicate application of Alkaline/ Surfactant/Polymer (ASP) process. The main objectives of this study are to (1) present progress of screening criteria for chemical EOR processes, (2) investigate the feasibility of Polymer flood (P), Alkaline/Polymer (AP), Surfactant/Polymer (SP), and Alkaline/Surfactant/Polymer(ASP) processes in low permeability carbonate reservoirs, (3) study the effect of using high concentration of surfactant in the ASP slug on oil viscosity and attained recovery, and (4) study the effect of initial oil saturation at the start of the ASP process on the oil recovery. Actual crude oil, formation brine, and low permeability carbonate reservoir samples are used to undertake this experimental study. Viscosity, pH, and Interfacial tension (IFT) for oil-water, and different chemical systems are measured. Additionally, eight core flood experiments are carried out to test different formulated chemical slug volumes and concentrations on oil recovery. The results indicated real progress in screening criteria of polymer EOR processes and thier successful applications in lower permeability reservoir (> 10 md). This study proved that ASP process is successfully applied as an enhanced oil recovery in carbonate reservoir having permeability less than 5 millidarcy (md). Moreover, addition of sodium hydroxide (NaOH), or surfactant (F75N) in polymer constituting a single slug has important effects on viscosity and pH of the different chemical slugs applied. The results also pointed out that the application of ASP process at higher mobile oil saturation leads to higher oil recovery than when applied at later stages of water flooded low permeability carbonate reservoirs. In addition, Alkaline/ Surfactant/Polymer (ASP) process has successfully recovered the highest recovery in comparison to other chemical processes. The application of the attained results develops a new window for more applications of chemical EOR processes in lower permeability carbonate reservoirs.

Low-density water-based drilling fluids formulated with hollow glass spheres (HGS) offer an attractive drilling method. HGS are incompressible lightweight additives with the capability to reduce mud weight down to 41.0 lbm/ft 3 (5.5 lbm/gal). Several pressure ratings of HGS are available, and selecting the appropriate rating is essential to avoid formation damage and lost circulation in near-balance conditions. Failure of the spheres could thus lead to catastrophic results. The objectives of this paper is to evaluate the stability of inhibited water-based drilling fluids formulated with HGS in diverse pH environments, and assess their potential application in Wasia formations in Saudi Arabia. Wasia formation is composed of middle cretaceous clastic rocks with layers of sandstone, shale and occasional limestone. Wasia is an aquifer with a thick unit that crops out in central Najd with a slight eastward dip ( Powers et al. 1966 ). The pressures of Wasia correlate to equivalent mud weights (EMW) of 51—58 lbm/ft 3 . This range of EMW is lower than that of water, and the use of conventional mud systems could introduce several operational difficulties due to the high hydrostatic pressure they create. The implementation of HGS-based lightweight fluids would lower the hydrostatic pressure in the wellbore, thus eliminating or reducing the frequent loss of circulation experienced in Wasia. HGS-based fluids could also provide greater protection of underground water resources, improve rate of penetration (ROP), and reduce or eliminate differential pipe sticking. We conducted comprehensive analysis of HGS performance in various pH environments to assess their stability in drilling fluids. Mud characteristics and rheological properties were examined before hot rolling (BHR) and after hot rolling (AHR) to determine the effects of high pressure and high temperature (HPHT) on the system. The duration at which the samples were exposed to HPHT conditions varied from 1 to 4 days to understand the behavior of the mud over time. In addition, two typical formulations were prepared using HGS and conventional additives to evaluate their properties and compare them to the American Petroleum Institute (API) standards. Hollow glass microspheres were found to be stable in the pH conditions of drilling operations (pH ~9), with a maximum density variation of 0.5 lbm/ft 3 . At higher pH levels (pH >11), the spheres experienced fractional dissolution due to the reaction of the added NaOH with borosilicate glass. In pH ranges lower than 4, the spheres were found to be extremely stable. The inhibited water-based fluids formulated with HGS produced favorable rheology and stable mud characteristics before and after exposure to the actual downhole temperatures of Wasia formation.

Drilling the top hole section in Egypt's Western Desert has proven to be a challenge because finding the optimal balance of drilling speed, pulling out of hole without issue, and running the casing without clay swelling is critical. Historically, a standard milled-tooth (MT) bit, slick BHA, and top hole mud system were used for economic considerations. Recently, a problem arose when drilling a 17½-in surface hole in the Western Desert Moghra sand and Dabaa area, where the formation is composed of swelling clays that caused delays and cost increases. The solution to combat clay swelling would require an effective mud strategy; a PDC design that could increase ROP and resist balling while remaining economic; and a slick BHA that ensured hole verticality without the aid of directional tools and minimizes the affect of drillstring dynamics for prolonged PDC bit life. The intent of such optimization is providing enough buffer time for the casing to be run without problems, and the overall solution needs to be more economic than the previous drilling practice. An integrated BHA, bit design, and mud strategy were deployed in a field test with outstanding results. The results showed a step-change in ROP performance and allowed a trouble-free hole. The PDC bit and slick BHA successfully mitigated vibrations and maintained verticality. The application of customized drilling fluid formulation that contained high-performance shale stabilizers with the redesigned mud-weight schedules and early fluid displacement resulted in significant enhancements in tripping while drilling as well as in running and cementing the 13⅜-in casing.

Efficiently drilling the deep lithology column with PDC bits in Egypt’s Western Desert (WD) has been extremely challenging. The formations—Alam El Buwaib, Masajid, Zahra, and Safa—contain a volatile mixture of highly interbedded sandstone, siltstone, and shale that have damaged PDC bits, especially at depths of 12,500 ft and greater. In addition to the demanding drilling requirements, operators are pursuing multiple targets per well for better cost optimization. Finally, a tight control on target drilling days has required more efficient and consistent drilling solutions. In addition, the array of different drive types and BHAs used in the area have all suffered and exhibited the same symptoms: high stick/slip, high shock and vibration, failure of MLWD tools, RSS, or positive displacement motor (PDM), and premature tripping for bit changeout. To solve the issues, several 8½-in PDC bits were developed that feature a central conical diamond element (CDE). The bit designs feature an abbreviated cutting structure profile at the bit center that generates a rock column that stabilizes the bit. The rock column is constantly being destroyed with axial force as opposed to traditional shear, resulting in lower torque magnitude and fluctuations. The reduction in torque fluctuations increases the bit’s potential to solve a combination of vibration issues. The new-style bits were scheduled to be field tested in different wells and runs in Egypt’s Western Desert applications, including with classical rotary BHAs, with different RSS/PDM types in a variety of directional well profiles, at different depths, and in different fields. This robust field campaign was performed with the intent of proving and providing a consistent solution and grounds for a paradigm shift of how PDC bits need to be constructed. The results of the multifield campaign delivered low levels of torque and torque fluctuations; enhanced bit durability, frequently replacing two bits or more; low vibration levels; a significant increase in cuttings size, thereby enhancing surface formation identification; and high dogleg capability and smooth directional response. The bits also increased footage and overall ROP due to preserving the cutting structure, producing a performance step change and achieving consistent lower cost per foot across the WD field. The field test campaign results in Western Desert spans over 60 runs conducted over a 12-month period. A close monitoring of the performance improvement has been tracked where the runs are rated against offsets. The rating is in terms of overall run performance, footage improvement, ROP increase, cutting structure condition, and overall dull grade. The new bits set over 30 new benchmarks.

Hydraulic fracturing for well performance optimization has been implemented for many years in BRN field in north-eastern part of Algeria, operated by Groupement Sonatrach-Agip (a JV between ENI and Sonatrach). Because of unfavorable petro-physical properties of the reservoir, some challenges have been encountered in avoiding any additional damage to the fracture faces and to facilitate the post-job treating fluids flowback. Effective fracturing treatment designs should consider preventive actions for possible fracture conductivity impairment, such as damage attributed to stress, proppant embedment, and damage caused by fracturing fluid residues. Correct proppant selection can minimize effects from stress and embedment, while a suitable fluid system can minimize conductivity impairment from gelling agent solid residue. Traditional guar-based fluid systems, which are often a preferred choice in the industry for fracturing operations, can have damaging effects on fracture conductivity attributed to inherent insoluble residue that can plug proppant pack pore spaces. Implementing a less damaging fluid system can not only maximize retained conductivity, but furthermore provide longer effective fracture half-lengths which may result in more efficient treatment fluid recovery. Therefore, to overcome such issues, a new fracturing fluid has been developed, leaving little or no residue after breaking. Moreover, this fluid system can be tailored to a wide variety of bottom-hole conditions and has comparable properties to guar-borate fluids with respect to proppant transport capacity and rheological characteristics (e.g. viscosity building and breaking behaviors). This paper presents the first successful implementation of this novel fluid system in the BRN field in Algeria for improving the water injection performance of a well characterized by a tight sandstone reservoir. Field data collected after performing the propped fracturing treatment confirm the effectiveness of the fracturing fluid design. Specifically, the following topics will be extensively described within this paper: Characteristics of the BRN field and history of conventional guar-base fluid systems used previously within this field; Specifics of the near residue free fluid system (cross-linker types, pH requirements, etc.); Design considerations for the implementation in the BRN field of this novel fracturing fluid; Results of post fracturing water injection performances.

The challenges in introducing new technologies or advanced innovations in the Operating Units of the E & P Companies are manifold and surprisingly it is not about a lack of ideas or missing skilled staff at all. While the mandate for any E & P company is to innovate or to lag behind, often the attempts of introducing new technologies and innovations do not succeed due to factors that were left out either at the planning or at the execution stage. On the other side in the Operating Units (OUs) often the subject is associated to an alien technology team coming from the Head Quarter offices, that is in charge of it and once they get the required data or complete the test they will be gone, thus missing the purpose of promoting and establishing an innovations friendly culture inside the organization. The smooth introduction of new technologies and innovations to overcome specific technical or operational requirement does not necessarily happen because the management has decided to do it or somebody outside the organization is pursuing that. Instead it requires following a tailor suited approach as creative processes are the result of well motivated staff rather than of a decree. Hereby an approach is proposed based on Three Key Factors and Seven Components to effectively introduce Innovations and New Technologies. The Key Factors are: The Prevailing Creative Energy Flow, The Alignment to the Company Goals, The first one is related to the dynamical interactions underlying the site/area/organization where the technology or innovation is pursuit. It is based on the fact that in every OU of an E & P Company that is delivering on a yearly production target there is a prevailing energy flow that already contains a great deal of creativity to cope with the dynamical changes of the oil and gas reservoirs and the operations. It is about recognizing this energy flow, its influencing factors, main actors, stream direction, etc. in order to be able to first get attached to it and then to steer it accordingly. The second one is about getting fully aligned to the specific company goals so that the innovation or technology is supported by all the stake holders. Further it is also about properly cascading down the company goals and to establish a mechanism that promotes effective participation of the staff, in both forms, as individuals and as a team. The last one is about being fully aware of the Main Components of the Technology and Innovation Life Cycle that beyond the technical also involves organizational, strategically, operationally and human resource aspects. The use of the proposed approach is shown in specific field case examples that document its effectiveness. Considering the specific features of the above elements will be reflected in shorter times from the idea generation to the field implementation. Moreover it enables a workflow that effectively encourages the participation of everybody in the organization in the introduction of new innovative ideas and Technologies thus supporting a continuous improvement mode and a shift to an innovations friendly organization.

The variety of available EOR techniques requires an in-depth screening to select a viable method that matches well to the reservoir rock and fluid parameters and still remains economically attractive. In the present paper a Comprehensive Integrated EOR Workflow is proposed that starts with an Advanced EOR Screening Method. This is comprised of both a Neural Network Part and an Operational Module. While the First part uses proven data mining techniques the Operational Module considers the specific features of the screened EOR Method influencing the field implementation. The Neural Network Part is based on an exhaustive review and selection of successfully deployed literature case. It uses the rock, fluid and other reservoir parameters to screen various EOR methods considering their technical-economical applicability. This Artificial Intelligence approach utilizes data mining techniques in the form of a hybrid system that makes use of a neural network as a screening tool and the genetic algorithm as an optimization tool to land into the optimum recommendation. The Operational Part enables to evaluate the implementation capability on the given field based on the specific requirements of the preselected EOR Method. The system works its way through the literature data of successful EOR projects trying to detect patterns and learning from the data the relationship between these characteristics and the feasibility of applying each EOR technique mimicking the ability of the human mind to learn from previous experience. The system is a multi-layers neural network whereby the input layer is composed of seven key reservoir parameters (depth, temperature, porosity, permeability, initial oil saturation, oil gravity and in-situ oil viscosity) while the output layer is composed of the probability of success of the evaluated EOR methods (steam, CO2 miscible, hydro-carbon miscible, in-situ combustion, polymer flooding). The number of hidden layers and neurons are optimized using genetic algorithm for best matching of the training data set and accurate prediction of the testing set. Comparing the system output with the actual applied EOR techniques in the field shows a reliable result with only a 5% miss-prediction of the total test fields. The Operational Module determines the deployment capabilities in the given reservoir considering the specific parameters of the pre-selected EOR Method, production-pressure history, Formation fluid flow properties and the actual field and well set up, thus providing an advanced EOR Screening.

Bir Rebaa Nord (BRN) and Bir Sif Fatima (BSF) fields, operated by Groupement Sonatrach-Agip (GSA, a JV between ENI and Sonatrach), are located in the Berkine basin in north-eastern Algeria. These fields are characterized by oil-bearing sandstone reservoirs with low to medium petro-physical properties. During the development phase, to counteract the effect of pressure depletion, water and gas injection was implemented for reservoir pressure maintenance. In addition, due to the increasing water cut, artificial lift systems were employed to effectively produce these fields. Hydraulic fracturing has been implemented in GSA since year 2000 to improve well performance, both in terms of productivity and injectivity for oil producers and water injectors respectively. The fracturing process has been improved over the years regarding operational procedures, enhanced reservoir knowledge and implementation of new technologies towards resolving the many uncovered challenges. Changes to the perforation strategy, fracturing fluids formulation, rock mechanics studies and design of proppant schedules are examples of enhancement to the fracturing practice that have been implemented in the recent years. One of the uncharted matters in GSA, coming out from the post-job data re-processing, was the necessity of a precise characterization of the hydraulic fractures vertical coverage. The presence of several sandstone layers with different properties brought questions if the fracture had grown into an unwanted zone or may had not properly covered the entire target formation. Moreover, fracture height is an essential parameter for frac models calibration. Its accurate determination drastically reduces the margin of error in treatment net pressure matching, helping to more precisely established fracture half-length and width, stress profile and, last but not least, achieving a calibrated model for future operations in the same area. This paper describes the successful implementation on two water injector wells of a novel non-radioactive detectable proppant for the first time in Algeria. The taggant material within the proppant has been located by comparing the pulsed neutron capture cased-hole logging passes registered before and after the hydraulic fracturing treatments. The detectable compound does not affect proppant properties and, in addition, its non-radioactive nature reduces the timing for materials delivery and eliminates the HSE risks linked to other tracing methods. The pulsed neutron measurements evaluation provided valuable information regarding fractures confinement, avoidance of contact with undesired layers and possible presence of cement channeling. Furthermore, combined with sonic logs and cores data, it helped refining the geo-mechanical model for future interventions design in the same reservoirs.

Screening criteria stage for the EOR applications is useful for many candidate reservoirs before expensive reservoir descriptions and economic evaluations are done. This paper presents the application of using fuzzy logic as an artificial intelligence technique in the screening criteria of the EOR technologies. EOR screening criteria have been developed based on field results. The database of 347 successful EOR projects worldwide is used to carry out statistical analysis which resulted in determination of four critical values (minimum, maximum, r1, r2) for each fluid and rock property. The determined values identify the suitable range of the rock and fluid properties and the screening criteria for each EOR method. In addition, these ranges can rate the properties of any field under study from 0 to 1 (through fuzzy logic membership functions). The minimum and the maximum values represent the successful boundaries of the fluid or rock properties for the studied EOR method; while r1 and r2 values represent the ranges with maximum rating (best conditions) for the fluid or the rock properties. Not all fields are amenable to EOR processes. Effective screening practices must be employed to identify suitable candidates. In the developed screening tool, there are 15 inputs representing EOR screening criteria of the reservoir rock and fluid properties including: API gravity, oil viscosity, reservoir depth, rock permeability, oil saturation, reservoir temperature, formation water salinity, net pay thickness, permeability variation coefficient (representing heterogeneity index), formation type, minimum miscibility pressure, initial reservoir pressure, current reservoir pressure, fracture pressure and an option showing if the reservoir is dip or not. The developed screening tool is characterized by an easily and friendly interface with additional options comparing to the other existing software or expert systems. The proposed tool can be used to support the decision making during the critical technology selection phase. Such study is an original contribution to achieve successful EOR applications.

By increasing worldwide energy demand and reducing reserves, enhanced oil recovery (EOR) from current fields has become more and more important. Moving from polymer to surfactant flooding, Chemical EOR has been considered an expensive method, and field applications have been decreased during the past two decades. Currently with the advent of nanotechnology, nanomaterials has been created and proposed to be used for EOR. Different nano materials with different sizes have been proposed. Among the various nano-material used for EOR applications, nano-silica with different sizes has been suggested. In this paper, a ball milling attritor has been used to produce nano silica from white sand. By operating the attritor for a different time, different sized formed. Four different sizes have been created after 5, 10, 15, and 25 hours milling. The size and shape of the powder particles were examined using x-ray diffraction (XRD) and field emission-scanning electron microscope (FE-SEM) while their microanalysis was performed by energy dispersive system (EDS). The prepared nano particles were found 140, 122, 100, and 87 nm after 5, 10, 15, and 25 hours of milling respectively. Several flooding scenarios have been tried to identify potential applications that will benefit upstream sector and oil recovery. A base run with water flooding (WF) was performed. The ultimate recovery factor by WF was found 67%. The ultimate recovery factors have been measured for these four nano materials and they are ranging from 65% to 77 %. To combine chemical EOR and nano materials, a mixture of nano material (87-nm) and polymer (xanthan gum) has been used as well, and its recovery factor is found 80%. The mechanisms of this development in the recovery has been explained. This paper summarizes new findings from several different experimental runs which shows the effectiveness of the nano silica particles for improving oil recovery over the traditional methods. Ultimately, the knowledge gained from this work can be used to improve and narrow the range of nano-size applications for improving the recovery factors and proposed a roadmap for ongoing and future research.