Marginal Reservoirs Research Articles

Depositional architecture of early rift non-marine systems and implications for reservoir development: Oligocene to Miocene Al Wajh Formation, Midyan Basin of Red Sea, Saudi Arabia

Exhumed early rift alluvial fan and braided fluvial fan systems are rare and consequently understanding facies distribution, stratal architecture, reservoir connectivity, and controls on stratigraphic development of these systems is quite difficult. The outcrops of early Oligocene to early Miocene Al Wajh Formation in the Red Sea region of Saudi Arabia provide an opportunity to investigate the depositional architecture and reservoir potential of an early rift alluvial to fluvial system. Eleven lithofacies (F1-F11) and four facies associations (alluvial fan facies association (FA1), braided fluvial fan facies association (FA2), floodplain facies association (FA3) and delta front facies association (FA4)) are identified in four subbasins (Maqna 1–2, Sukk and Ifal), suggesting deposition in an alluvial-braided fluvial fan system. FA1 (36–100%) and FA4 (9–13%) have higher relative proportion and widely distributed in the northern subbasins (Sukk and Ifal subbasins) while the relative proportion of FA2 (50–82%) and FA3 (18%) increases towards southern subbasins (Maqna-1 and Maqna-2 subbasins). Distribution of facies associations, relative reduction in the clast diameter, and general southward paleoflow direction suggest that the northern subbasins (Sukk and Ifal) represent the proximal settings and southern subbasins represent medial (Maqna-1 subbasin) and distal settings (Maqna-2 subbasin) of a large alluvial-braided fluvial fan environment. Stratal architecture of proximal conglomeratic channel deposits highlight that despite reasonable thickness and spatial connectivity (several meters), these deposits may have marginal reservoir quality because of poor sorting and high matrix content. Sandstone beds occurring in medial settings have a higher potential to act as hydrocarbon reservoirs by displaying excellent reservoir properties on the account of their significant thickness (up to few meters), coarse grain sizes, better sorting, considerable spatial connectivity (10s of meters) and lower proportion of interbedded mudstone.

Mathematical modeling of casing exit windowing by swirling abrasive jet

Casing windowing constitutes a pivotal operation in the functionality of short-radius horizontal wells aimed at harnessing marginal reservoirs. The swirling abrasive jet (SAJ) windowing technology emerges as a notable candidate for windowing processes, distinguished by its rapid cutting abilities, elevated safety standards, and benign environmental impact. Nonetheless, the absence of comprehensive theoretical inquiry has obscured the understanding of the SAJ windowing mechanism, and the parameter selection process remains devoid of a theoretical framework, thus impeding its practical deployment. This investigation introduces a mathematical model for SAJ windowing, incorporating the influence of both jet and nozzle structural parameters on the efficiency of the windowing process. Specific jet parameters examined include jet pressure, standoff distance, and abrasive concentration, while nozzle characteristics are defined by nozzle diameter and impeller outlet angle. The theoretical model's fidelity is substantiated through experimental validation. Findings indicate that windowing duration diminishes exponentially as jet pressure, abrasive concentration, nozzle diameter, and impeller outlet angle increase, whereas the windowing diameter exhibits a linear augmentation with standoff distance and impeller outlet angle enhancements. Optimal conditions were identified as a jet pressure of 15 MPa, standoff distance of 35 mm, abrasive concentration of 5%, nozzle diameter of 4 mm, and an impeller outlet angle of 39°. This research furnishes theoretical underpinnings for parameter selection in the SAJ casing exit window cutting technique.

DETERMINATION OF PETROPHYSICAL PROPERTIES CUTOFF IN HETEROLITHIC RESERVOIRS IN MALAY BASIN

Thinly bedded sand-shale heterolithic are commonly found as a marginal reservoir in the Malay Basin. In the evaluation of heterolithic reservoirs, a key challenge is to determine the appropriate petrophysical properties cutoff. This study used the Modular Dynamic Tester (MDT) pressure tests to determine the appropriate petrophysical properties cutoff applicable to heterolithic intervals. Intrinsic permeability analysis and MDT mobility plots were used to determine the cutoffs for shale volume and total porosity. Subsequently, hydrocarbon pore volume thickness (with shale volume and porosity cutoff applied) was plotted against water saturation to determine the water saturation cut-off value. In this case study, the reservoir cutoffs applied are shale volume less than 60% and total porosity in excess of 12 %. The hydrocarbon pay cutoff was set at a water saturation less than 85 %.

Hydrocarbon accumulation conditions and exploration targets of the Sinian Dengying Formation in the Southeastern Sichuan Basin

No breakthrough has been made in petroleum exploration of the Sinian Dengying Formation in the southeastern Sichuan Basin as the major factors controlling the hydrocarbon accumulation of the Dengying Formation have not been well established, including the development period and distribution of the platform margin, the effectiveness of the source-reservoir combination and the reliability of the Cambrian pre-salt structural trap. Based on the interpretation of seismic data and hydrocarbon-source correlation, the distribution of the platform margin of the Sinian Dengying Formation in the southeastern Sichuan Basin was mapped. Moreover, the gas source rocks of the Dengying Formation were clarified according to geochemical characteristics of fluid inclusions, and the pre-salt structures were further confirmed by seismic forward modeling and experiments of prestack depth migration. Results showed that the sedimentary facies of the 4th member of Dengying Formation in the southeastern Sichuan Basin was platform margin of gentle slope type. The platform margin reservoir of the Dengying Formation and the Lower Cambrian source rocks constitute a favorable source - reservoir combination. The carbon isotope characteristics of gas in fluid inclusions indicate that some of the oil/gas in the Dengying Formation were contributed by the Doushantuo Formation source rocks. As the difference in seismic velocities between carbonate rocks and gypsum/salt beds may cause a reduction in the amplitude of pre-salt structures, the low-amplitude structures identified on current seismic profiles are underestimated instead of overestimated. Accordingly, the Sinian structural traps are confirmed to develop in the deep pre-salt sequences in the low-steep anticline belt, southeastern Sichuan Basin. On the basis of the above new understanding, we propose two types of hydrocarbon migration modes for the Sinian Dengying Formation in southeastern Sichuan Basin, including lateral migration of hydrocarbons generated from the Cambrian Qiongzusi Formation and vertical migration of hydrocarbons derived from the Sinian Doushantuo Formation. Lithologic traps at the platform margin and pre-salt structural traps within the platform are favorable targets for natural gas exploration.

INTEGRATED COMPLETION STUDY FOR HPHT SOUR GAS WELL DEVELOPMENT IN CARBONATE RESERVOIR X

Recently, Indonesia will lead to gas deficits since the increase in domestic gas demand in 2040. The increasing need for energy sources and the decreasing available reserves have encouraged oil and gas companies to explore and manage marginal reservoirs such as sour gas environment to maintain the balance of energy supply and demand. The gap in gas supply-demand will decrease by 20% due to the supply of Natuna Gas Field, as the example of potential sour gas environment (Batubara, 2015). Thus, it is very relevant to develop this potential source immediately.
 Also, sour gas field approximately shares 40% of Indonesia’s total proven gas reserve with an estimated OGIP of around 222 TSCF, with 75% of gas recovery. Unfortunately, sour gas environment cannot be produced economically since the it has high carbon dioxide (CO2) and hydrogen sulfide (H2S) content, which are toxic and corrosive.
 The X sour reserves contain 32% carbon dioxide (CO2) and 7072 ppm H2S with fluid gravity of 42 API. This discretionary source of CO2 was recently brought into production from one well with depth of 8400 ft. The well was perforated in a limited interval of 7100 until 7700 ft. The harsh environment presented many challenges to completion design. Unique equipment and material selection were required.
 This study aims to determine the reservoir fluids and production performance also predict the corrosivity of CO2 dissolved in the natural gas. With the simulation and prediction, it can be obtained the proper material and equipment selection based on the sour service needed. As a result, the wet gas reservoir of X field can produce optimum rate of 19.1063 MMSCFD. For completion design, Nickel Alloy SM2535 or SM2242 is needed as there will be damage in form of corrosion and pitting.

Generando ingresos a partir de objetivos económicamente no rentables. Implementación exitosa de técnicas de fractura HiWAY & TSO en el Campo Shushufindi

The giant Shushufindi field, discovered in 1968, is located in the North-East of the Orient basin in Ecuador, neighboring Maranon and Putumayo basins in Peru and Colombia, respectively. The field belongs to Block 57, it started production in 1972 and is sparsely developed with 165 active wells. The production comes from two of the main cretaceous reservoirs: Ti and Ui, with Ts, Us and BT as secondary targets. The challenge to obtain incremental production from the main reservoirs becomes a tough task. The emphasis on producing from the secondary reservoirs turns into a crucial target for meeting the production expectations in the low production or abandoned wells. The main challenges in the secondary reservoirs are intermediate petrophysical properties, stratigraphic variability, low pay, lateral discontinuity, and shale intercalations. However, there is an important volume of recoverable volumes associated in these sands that makes them an attractive target for production enhancement. Performing conventional operation in secondary reservoirs has a wide margin of risk in terms of incremental production, where the average oil production is ~120 BOPD. A strategy to improve conductivity in these marginal reservoirs is hydraulic fracturing. Induced fractures enhance permeability greatly by connecting pores together; with this, hydraulic fracturing becomes a critical technology to increase production. The effectiveness of hydraulic fracturing is determined by the propped conductivity and geometry,the fracture height, and half-length. Pad volume and proppant concentration also play an important role in the fracture-treatment design because they determine final propped fracture penetration and conductivity. A good understanding of the reservoir characteristics, together with a fit-to-purpose fracture design, led to a successful implementation of TSO and HiWAY fracture designs in the Shushufindi field, with outstanding results. During the 2018-2019 WO campaign, nine (9) well interventions involved hydraulic fracturing in secondary targets and two (2) in main targets. The execution of these jobs exceeded expectations generating oil production of 7000 BOPD (790 BOPD/well) after the jobs and revenue to the project, which translates to an estimated 6.9MM Bbls of recoverable reserves.

Diversity of deformation structures in varves of the Weichselian Pyrzyce Basin (NW Poland)

Within the sediments of the Pyrzyce Ice-dammed Lake (Polish Lowlands), a number of soft-sediment deformation structures (SSDS) in varve series were distinguished. The unique morphology of the ice-dammed lake—the occurrence of level IV overload and the presence of dead ice in the central zone (Lake Miedwie) and the marginal reservoir—had a decisive impact on the formation and nature of sedimentary structures. Dead ice melting and loss of support could be the cause of plastic deformation. The highest intensity deformation in layered sediments of both plastic and rigid types was observed in the marginal (highest) part of the reservoir. Their formation is associated with the melting of rooted lumps of dead ice in sub-aquatic conditions. The exception is deformation resulting from desiccation under subaerial conditions. The genesis of the deformation observed in rhythmically-layered varves is associated with the last stage of functioning and disappearance of the reservoir during the recession of an ice sheet of the Pomeranian phase of the Weichselian glaciation. These studies detail the current state of knowledge on the processes and factors responsible for the formation of soft structures occurring in glaciolimnic basin.

Exploiting Microbes in the Petroleum Field: Analyzing the Credibility of Microbial Enhanced Oil Recovery (MEOR)

Crude oil is a major energy source that is exploited globally to achieve economic growth. To meet the growing demands for oil, in an environment of stringent environmental regulations and economic and technical pressure, industries have been required to develop novel oil salvaging techniques. The remaining ~70% of the world’s conventional oil (one-third of the available total petroleum) is trapped in depleted and marginal reservoirs, and could thus be potentially recovered and used. The only means of extracting this oil is via microbial enhanced oil recovery (MEOR). This tertiary oil recovery method employs indigenous microorganisms and their metabolic products to enhance oil mobilization. Although a significant amount of research has been undertaken on MEOR, the absence of convincing evidence has contributed to the petroleum industry’s low interest, as evidenced by the issuance of 400+ patents on MEOR that have not been accepted by this sector. The majority of the world’s MEOR field trials are briefly described in this review. However, the presented research fails to provide valid verification that the microbial system has the potential to address the identified constraints. Rather than promising certainty, MEOR will persist as an unverified concept unless further research and investigations are carried out.

A comparative study on natural gas hydrate accumulation models at active and passive continental margins

The comparative study on natural gas hydrate accumulation models between active and passive continental margins as well as their controlling factors is of great significance to the guidance of natural gas hydrate exploration. Based on the data and research results of international typical active continental margin hydrate accumulation areas such as the Cascadia margin of the Northeast Pacific, the Nankai trough, etc. and passive continental margin areas like the Blake Ridge, the models of the gas hydrate accumulation system are summarized and numerically simulated, and a preliminary comparison of active and passive continental margin reservoir accumulation models was also carried out. The following results were obtained. (1) The active continental margin provides a driving force and channel for vertical gas migration, which induces deep free gas and in-situ biogas to migrate along the fault. The migration channels are mainly faults, fractures and slumps produced by subduction–accretion. (2) Coarse-grained turbidity sediments such as silt and sandy silt have good porosity and permeability. Moreover, the sediment thickness on the accretionary wedge is large, which provides a good storage space for hydrate accumulation. (3) Numerical simulations of the Blake Ridge, and Niger Delta hydrate accumulation show that the passive continental margin lacks the lateral stress caused by the subduction zone compared with the active continental margin. However, due to the plastic materials in the thick sedimentary layer, high-pressure fluids and volcanic activities outside the continental margin, vertical accretion and tensile stress are generated and the accumulation rate of diffusion-type hydrates mainly depends on the methane supply rate. (4) Organic matter content, gas production rate, geothermal gradient and sedimentation rate at the passive continental margin have different effects on the spatial distribution of hydrate content. Mud volcanoes or diapir structures provide an ideal place for the formation and occurrence of hydrates.

E&P Notes (October 2020)

E&P Notes (October 2020)

Development of Hybridized Completions for Extended Reach Horizontal Wells

Non-uniform production and injection profiles in extended reach horizontal wells invite several production and recovery issues. Downhole flow control devices, along with dynamic reservoir modeling, have been beneficial in regulating flow, improving productivity from the toe section, delaying water breakthrough, reducing water coning, and improving overall reservoir sweep. However, such measures add to substantial completion costs and may not be economical for marginal reservoirs. Using simple slotted liners is a cheaper option but may not be effective in regulating injection/production profiles in the longer term. This research focused on applying “coupled static and dynamic modeling” to examine and compare five different types of completion designs, using data from a heterogeneous carbonate reservoir. Results show that inflow control device (ICD) integrated completions can achieve better recovery than the slotted, pre-perforated, or engineered liners. Engineered-slotted liners perform better than the pre-perforated-slotted liners. The pre-perforated-slotted liners do not show much improvement over open-hole completions. Finally, a hybrid completion design is optimized by combining ICD with engineered-slotted liners, which showed higher well productivity, lower water cut production, and reduced completion cost.

Geology-engineering integration for low-permeability and thin marginal reservoirs: a case study on Zanazour oilfield, Pre-Caspian Basin

Geology-engineering integration for low-permeability and thin marginal reservoirs: a case study on Zanazour oilfield, Pre-Caspian Basin

Engineering Miracles: A Short Distance Between Creation and Value to Society

Special Section: The Value and Future of Petroleum Engineering In the JPT issue celebrating SPE’s 50th anniversary, John C. Calhoun addressed how distinctive petroleum engineering is from other engineering disciplines: “During the past several decades, consolidation and integration of four major elements of petroleum engineering have occupied the profession. The following lists these elements. Extending our capabilities to gain access to, to couple with, and to operate within a greater portion of the subsurface environment (e.g., offshore locations, over-pressured environments, marginal reservoirs, horizontal drilling, complex flow systems, acidizing, and hydrofracturing). Developing methods for detailed characterization of subsurface formations, their fluids, and their surroundings (e.g., geostatistics, well logging, indirect geophysical measurements, well-performance analysis, and basin analysis). Recovering a greater proportion of the petroleum within reservoirs that have been accessed and understanding the transfer operations that accompany the recovery (e.g., a broadened spectrum of injected fluids and fluid additives, phased fluid injection programs, extensions of reservoir flow paths, in-field drilling, and horizontal wellbores). Systematizing technological management and coupling it with business decision making (e.g., history matching, risk analysis, reservoir management, software packages, and team projects).”1 Since that issue a little over a decade ago, petroleum engineering feats have expanded on the past and made towering breakthroughs in resource recovery. Those breakthroughs came about with added emphasis on decision and risk analysis as an essential project element; a step up from what was referred to as a coupling with business. Reviewing our technology history thus requires highlighting the tangible breakthroughs with the necessary intangibles that enabled faster transformations with commercial success (Fig. 1). Tangible Breakthroughs Arguably the biggest breakthrough during the past 50 years was Mitchell Energy’s approach to making shale production viable. Well stimulation began in the mid-1800s with torpedoes used on Pennsylvania wells. It was the subject of the first JPT technology article published in 1949, “A Hydraulic Process for Increasing the Productivity of Wells,” by J.B. Clark.2 Mitchell’s approach was not so destructive as the torpedo approach and packed more energy per square nanometer to tip the scales of global supply sourcing. By leveraging the refinement of existing technologies, such as slickwater fracturing adopted from Union Pacific Resources Group, Mitchell’s engineering ushered in new sources of economic reserves, rebalancing top global supplier positions between North America and the Middle East. An equal contributor to shale success was horizontal drilling. While slant drilling was derisive in the 1920s, legal and more reliable horizontal drilling evolved with major advancement in the 1970s through the use of mud motors, “bent subs,” whipstocks, and measurement-while-drilling tools. The petroleum engineer’s ability to reduce trips, monitor, and course correct through tight lateral intervals advanced getting wells on production sooner, with lowered risks and better financial results. Direct public benefit from results such as this are exemplified by the number of sovereign wealth funds established using oil and gas proceeds: the Alaska Permanent Fund, Texas Permanent University Fund, and funds in Norway and the Middle East, to name a few.

Study and Application of Hydraulic Jet Radial Drilling in Carbonate Reservoirs

The hydraulic jet radial drilling technology is a low-cost production and completion technology for effectively developing low-permeability marginal reservoirs, thin-bed reservoirs with edge and bottom water, and depleted oil and gas fields. It has been successfully and widely applied in sandstone, coalbed methane, and heavy oil reservoirs. In order to explore its application in carbonate reservoirs, specially economically and efficiently develop low-permeability thin-layer carbonate reservoirs, the pilot of hydraulic jet radial drilling technology in the carbonate reservoir application was successfully completed through the research on the principle, advantage, existing problems and application condition of radial jet drilling, economic productivity was got, and cost-effective development was achieved, this pilot provided a method for the development of low permeability thin layer carbonate reservoir. This research shows that the hydraulic jet radial drilling technology has its unique technical advantages, which can enable some reservoirs to increase production or injection, but it is not suitable for every well, it has certain applicable conditions, such as the depth, thickness, and temperature of the target zone, and the conditions of well inclination, casing and wellbore have certain requirements too. The hydraulic jet radial drilling technology can achieve the expected target based on the zone and well selection, in selecting layers, as far as possible, homogeneous oil layers with good reservoir physical properties should be selected; the key of its successful implementation is the depth and azimuth control, wellbore diameter and operation safety control. The application of hydraulic jet radial drilling in carbonate reservoirs will make the spray hose wear large due to its high Young's modulus the high hardness, which affects the treatment footage; the use of acid in jet drilling can increase the radial drilling footage, but on the other hand can also produce impurities affecting the operation. The working fluid for jetting must meet the requirements of no solid phase.

New Multilayer Boundary-Detection Service in Bohai Bay, Northern China

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176442, “New Multilayer Boundary-Detection Service Employed in Complex and Mature Reservoir in Bohai Bay, Northern China,” by Xija Guo, Yong Jia, Kai Fan, Liuhe Yang, and Guoquan Zhao, CNOOC, and Kai Wu, Fei Wang, Cang Li, and Zhujun Gao, Schlumberger, prepared for the 2015 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Nusa Dua, Indonesia, 20–22 October. The paper has not been peer reviewed. Bohai Bay is northern China’s largest offshore basin. Its predominant depositional environment is a shallow delta and a meandering river system complicated by faults, an arrangement that leads to fully developed interbed interference and high geological uncertainty when horizontal wells are drilled within the greenfield. As a solution to resulting challenges, a new multilayer boundary-detection service has been introduced. This paper illustrates a case study in which this technology was applied. Introduction In 1967, CNOOC began commercially operating the oil and gas resources of the Bohai Sea (Fig. 1). Since then, more than 100 production platforms have been put into operation in a 43 000-km2 exploration area, including both development projects on the greenfield and infill projects on the brownfield. After long-term development and production, an increasing number of conventional reservoirs have a depleted hydrocarbon capacity and the field’s water cut has increased quickly. Thus, the CNOOC client began to focus on the complex marginal reservoir and the infill projects of the brownfield. The focus of this paper is to help achieve the geological objectives and, furthermore, optimize production by use of the new multilayer boundary-detection service. Background General Geology. The Bohai Bay basin formed at the end of the Tertiary on a crystalline basement solidified from the Archeozoic to the Early-Middle Proterozoic. After deposition in the Middle to Late Proterozoic and the Paleozoic, Mesozoic, and Cenozoic, a complex fluvial channel system was generated with features such as disconnected and isolated sand bodies, mingled structures between the hydrocarbon reservoir and aquifer, inconsistent properties both vertically and laterally, and fully developed heterogeneity. As of 1994, the Bohai Bay basin has been known to consist of 47 faulted depressions, in which 170 oil and gas fields have been found.

Comprehensive insight of the Cambrian carbonate platform types as well as margin segmentation characteristics' exploration in Tarim Basin, China

The carbonate platform types and features of the platform margin belt plays an important role in controlling the reservoir formation; it also affects the relationship between reservoirs and caps. The Cambrian carbonate platform in the Tarim Basin underwent three evolutionary processes, namely, the Early Cambrian ramp platform, the Middle Cambrian edging evaporative platform, and the Late Cambrian edging platform; the northern platform margin was the deposition type, whereas the eastern platform margin was for fault control, additionally, the Lungu-Gucheng had evident sectional differences. The line from Wushi-Kashi-Maigaiti-Hetian to Minfeng of the southwestern Tarim Basin was an ancient land in the Early Cambrian. Through evolution, the sea level raised the underwater lows in the Middle and Late Cambrian period that possibly developed it to platform edge deposits in the Late Cambrian. The carbonate platform margin of both steep slope and gentle slope formed different reservoir-seal assemblages. The Upper Cambrian aggradation-progradation platform margin reservoir in the steep slope of the eastern Lungu and Gucheng area was developed with good connectivity, its caprock had been always the key of the platform margin reservoir-seal assemblages. Therefore, the reef-beach located behind the platform margin belt near the seaside of the lagoon had favorable reservoirs; the reservoirs often overlaid carbonate caprock which formed good reservoir-seal assemblages. The platform margin belt in the gentle slope in the Well Yingmai 7-Well Yingmai 8, in west Tabei, was a dolomite reservoir for algal mound and reef-bank complex with caprock of middle-lower Cambrian dolomicrite, gypsum dolomite, and mud dolomite. Aforementioned dense layers' reservoir-seal assemblage was superior to that of the eastern Lungu and Gucheng that had better exploration prospects.

水平井井眼轨迹控制误差分析

随着诸多新型定向井、水平井(如分支井、丛式井、大位移井、绕障井、SAGD水平井、火驱井等井型)的应用，所钻遇的地质环境日趋复杂，在井眼密集的老区和超薄边际油层钻井中，对水平井井眼轨迹监测与控制的精度要求越来越高。由于随钻测量仪器在测量过程中由于受到环境、仪器精度、磁场变化等因素影响，实钻井眼轨迹就会与设计轨道产生偏差。认识测量仪器误差对轨迹控制的重要性，减小井眼轨迹控制的误差，提高井眼轨迹的控制精度，可以有效降低井眼防碰的风险，也可以提高水平井的中靶精度，对水平井的现场施工具有重要的指导意义。 With many new directional wells and horizontal wells (such as Multilateral wells, Cluster wells, ERW, SAGD, Fire Flooding wells) application, the geological environment is becoming more com-plex. The accuracy requirement of monitoring and controlling the trajectory of horizontal well in drilling is higher and higher, especially in the old wells and ultra dense marginal reservoirs wells. Due to the environment, the precision of the instrument, the change of the magnetic field, and so on, the influence of the factors on the measuring instrument in the measuring process is measured. So there is deviation between the real drilling trajectory and design trajectory. By recognizing the importance of measuring instrument error on trajectory control, this error can be reduced in slim hole trajectory control, and it also can improve the control precision of the well trajectory. It can reduce the risk of well drilling and improve the accuracy of the target. It has great realistic significance to field operation.

Analysis of Slimhole Drilling Technology Application in Shengtuo District

In order to develop marginal oil reservoir and save drilling cost,since 2006 Shengli Oilfield began to do research of slim hole drilling technology. After a summary trial of 13 wells in Shengtuo area, Analysis the existence of technical difficulties and solutions of slimhole. Preliminary formed a set of suitable technology for Shengli oil field, especially the slim hole drilling in Shengtuo area, The average penetration rate reached 18.39m/h, The average drilling period is 10.69d. The experience provides reference to the same kind of wells in shengli oilfield.

A New Strategy Explores Tight Oil/Gas Reservoirs: Fit-for-Purpose Acid Fracturing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164778, ’A New Strategy To Explore Tight Oil/Gas Reservoirs: Fit-for- Purpose Acid Fracturing,’ by G.M. Hegazy, SPE, and Adel M. Salem, American University in Cairo and Suez University; Shedid A. Shedid, British University in Egypt; Shouhdi E. Shalaby, Suez University; and J. Abbott, Schlumberger, prepared for the 2013 North Africa Technical Conference and Exhibition, Cairo, 15-17 April. The paper has not been peer reviewed. As oil companies have moved to more-marginal reservoir targets, application of conventional techniques has often yielded disappointing results, and tighter zones are often abandoned for more-promising target intervals. Marginal reservoirs may require horizontal-well drilling or multiple-stage hydraulic fracturing to achieve economic production targets. In an effort to reduce risks and costs associated with these alternative processes, a new stimulation strategy has been adopted for tight intervals using vertical wells before going to horizontal wells. Resources Availability There are tens of undeveloped reservoirs and even undiscovered plays/prospects in the area of this study (Abu Dhabi). These new plays and undeveloped reservoirs contain huge quantities of stock-tank oil initially in place (STOIIP). Most of these reservoirs are still in the appraisal phase, and tremendous efforts are required to bring the best reservoirs to the top of the development portfolio. The decision to transfer a single reservoir from appraisal to development mostly depends on STOIIP ranking, which in turn takes into account the following factors. Exploration-, Appraisal-, and Development-Data Investigation. The study investigates 51 reservoirs allocated with-in 14 fields under the appraisal portfolio, and three exploration reservoirs dis covered recently after applying the new concept of fit-for-purpose acid fracturing. The work is extended to include a development reservoir in which long-horizontal-well drilling is implemented while the study recommends fracturing implementation. Fig. 1 illustrates the distribution of STOIIP percentage among the three phases of exploration, appraisal, and development. The investigation of well-test results shows that more than 180 wells were tested in the area of the study. For 98 wells, the test results were considered inconclusive because of either reservoir tightness or improper stimulation treatment, or both. Reservoir Ranking by STOIIP. On the basis of STOIIP ranking results, 13 reservoirs out of a total of 54 were ranked highly, with a minimum of 100 million STB. These reservoirs represent 77% of the total STOIIP of the portfolio. Not all of these high-STOIIP reservoirs could produce with matrix-stimulation treatment, however, because the permeability of 12 reservoirs is less than 4 md. In the class of reservoirs ranging between 100 and 50 million STB, 17 reservoirs represent some 17% of the total STOIIP of the portfolio. The remaining reservoirs are very small, with STOIIP values of less than 50 million STB.

Technology Focus: Well Stimulation (June 2013)

Technology Focus This past spring, I had the opportunity to review more than 100 SPE paper abstracts as well as numerous full papers from those abstracts. To SPE’s credit, these abstracts all represent high-quality papers, making it difficult to select those to be highlighted for this feature. The papers chosen for highlighting are those that represent some of the challenges our industry faces and solutions shown to help overcome these challenges. The nonproppant well-stimulation trend continues to be acidizing of the carbonates. What really stands out is the industry emphasis on the continued move to marginal reservoir targets (i.e., poor-quality carbonates as well as sands and shales). For this move to be successful, long-reach horizontal wells are being used. Along with the long reach comes reservoir heterogeneity and the commensurate need for zonal isolation. Or, said another way, the need is to ensure that the entire interval gets the required treatment in these low-quality reservoirs. Last year, after a similar review, it was apparent that horizontal wells and proper acid placement were priorities. The subject that seemed to prevail was distributed-temperature-sensing and distributed-acoustic-sensing diagnostics. This year, the published-literature emphasis is on methods and required equipment to achieve better acid placement. The papers chosen to be summarized are excellent resources related to this emphasis. The first paper, Improved Methods and Workflows for Multizone Stimulation, illustrates tools and workflows that have improved multizone-stimulation effectiveness. The second paper, Optimization of Limited-Entry Matrix Acid Stimulations With Laboratory Testing and Treatment Pressure Matching, is of importance because it discusses the application of acid jetting in long horizontal chalk wells but also addresses pressure drop across perforations. The paper further focuses on the elusive perforation coefficient used by many of us in the design of limited-entry zonal stimulation. And the third paper, A New Strategy To Explore Tight Oil/Gas Reservoirs—Fit-for-Purpose Acid Fracturing, demonstrates the value of a strategy to improve on the success in poor-quality reservoirs. The first additional-reading paper, Successful Application of a Fit-for-Purpose Acid Program in the Tengiz Field, demonstrates application of this approach. Recommended additional reading at OnePetro: www.onepetro.org. SPE 160804 Successful Application of a Fit-for-Purpose Acid Program in the Tengiz Field by K. Ussenbayeva, Chevron, et al. SPE 162238 Acidizing—Lessons From the Past and New Opportunities by Robert Taylor, Halliburton, et al. SPE 160762 Successful Application of Foamed-Acid Stimulation of Severely Damaged Perforations in a Horizontal Intelligent Well by W. Ruksanor, Sakhalin Energy Investment Company, et al. SPE 163384 Unique Process and Tool Provide Better Acid Stimulation and Better Production Results by Mishari Al-Saqabi, Kuwait Oil Company, et al.