Unconventional Carbonate Research Articles

Novel insights to unconventional carbonate mudstone reservoir with quantitative nanoporosity characterization and modeling of Tuwaiq Mountain Formation

Organic-rich carbonate mudstones have emerged as a significant unconventional play globally, particularly the Middle Jurassic carbonate mudstones of the Arabian plate. Despite their importance, these mudstones are highly heterogeneous, composed of organic-lean and organic-rich deposits, and often exhibit similar reservoir quality, making them challenging to characterize. While most studies have attributed the reservoir quality of these mudstones to the organic-related pores, little attention has been paid to the origin of the pore structure and network of the organic-lean counterparts. To address these issues, we performed high-resolution quantitative pore characterization and modeling by coupling micro-computed tomography and focused ion beam scanning electron microscopy to gain insight into the matrix-related pore structure, size, and networks on the organic-lean mudstones. Our study showed that in the organic-lean mudstones micropores are present but isolated, while the nanoscale pore structure appears to be well-connected, hence higher permeability. The pore-network model result has a median pore radius of 189–226 nm and a median throat radius of 91–112 nm, rarely exceeding 1000 nm and 500 nm, respectively. The frequency plots demonstrate positively skewed distributions indicating that large pores and throats are anomalous. Our study highlights that the organic-lean mudstone nanoscale pores are comparable to previously reported nanopores in the organic-rich zone and other mudstone plays around the globe. It emphasizes coexisting organic and matrix-related nanopores, suggesting the significance of matrix-bound nanopores' influence on carbonate mudstones unconventional play. The findings can enhance our understanding of the nano-scale pore structure and provide insights to evaluate and build development strategies of carbonate mudstones in the Arabian Intrashelf Basin and elsewhere.

3D Microporosity Characterizations in the Heterogeneous Middle Jurassic Tuwaiq Mountain Formation: Insights into an Unconventional Sweet Spot.

Carbonate microporosity can vary significantly across depositional lithofacies and cycles, owing primarily to the high degree of heterogeneity in their pore sizes, pore throat radius, geometry, and connectivity. This is further compounded by the complex diagenetic alterations during various stages of burial. In addition, the presence of micropores, which are abundant in carbonate rocks, but not visible using conventional techniques, is challenging to characterize. To address this issue, our study focused on the Middle Jurassic Tuwaiq Mountain Formation (TMF) due to its importance as an analogue to subsurface conventional and unconventional reservoirs. Here, we utilized eight samples and performed pore network modeling to quantify microporosity distribution and connectivity from high-resolution microcomputed tomography images of different microfacies (MF) in the TMF from both mud- and grain-dominated facies. These results were then validated with petrographic, SEM images, and porosity-permeability measurements. Our study revealed that, in the high-energy, grain-supported microfacies of the shallow lagoon depositional cycle, micropores dominated by interparticle and microvug types were abundant and well-connected, with mean pore and throat sizes of 7 and 4 μm. Conversely, micropores within the low-energy mud-dominated microfacies of the deep lagoon depositional cycle dominated by intraparticle and intercrystalline types were isolated and rarely connected, even at the microscale (1-4 μm in diameter, with an average of 2 μm). This result suggests that pore connectivity at the microscale is not always related to matrix porosity, and the pore connectivity is present in submicron scale, which goes against common concepts in unconventional carbonate reservoirs. Furthermore, our observations indicate that primary depositional processes play a major role in controlling the distribution and connectivity of the Tuwaiq Mountain Formation's microporosity, while diagenetic processes only have minor controls. Our study emphasizes the importance of characterizing microporosity and its connectivity in heterogeneous carbonate rocks, which may reduce the uncertainty in exploring the properties of complex carbonate reservoirs worldwide.

Pre-Stack Fracture Prediction in an Unconventional Carbonate Reservoir: A Case Study of the M Oilfield in Tarim Basin, NW China

The reservoir of the M oilfield in Tarim Basin is an unconventional fracture-cave carbonate rock, encompassing various reservoir types like fractured, fracture-cave, and cave, exhibiting significant spatial heterogeneity. Despite the limited pore space in fractures, they can serve as seepage pathways, complicating the connectivity between reservoirs. High-precision fracture prediction is critical for the effective development of these reservoirs. The conventional post-stack seismic attribute-based approach, however, is limited in its ability to detect small-scale fractures. To address this limitation, a novel pre-stack fracture prediction method based on azimuthal Young’s modulus ellipse fitting is introduced. Offset Vector Tile (OVT) gather is utilized, providing comprehensive information on azimuth and offset. Through analyzing azimuthal anisotropies, such as travel time, amplitude, and elastic parameters, smaller-scale fractures can be detected. First, the original OVT gather data are preprocessed to enhance the signal-to-noise ratio. Subsequently, these data are partially stacked based on different azimuths and offsets. On this basis, pre-stack inversion is carried out for each azimuth to obtain the Young’s modulus in each direction, and, finally, the ellipse fitting algorithm is used to obtain the orientation of the long axis of the ellipse and the ellipticity, indicating the fracture orientation and density, respectively. The fracture prediction results are consistent with the geological structural features and fault development patterns of the block, demonstrating good agreement with the imaging logging interpretations. Furthermore, the results align with the production dynamics observed in the production wells within the block. This alignment confirms the high accuracy of the method and underscores its significance in providing a robust foundation for reservoir connectivity studies and well deployment decisions in this region.

Characterization and classification of the microporosity in the unconventional carbonate reservoirs: A case study from Hanifa Formation, Jafurah Basin, Saudi Arabia

Formation porosity is a key factor that exerts substantial control upon reserve estimates, and ultimately may affect the development viability of unconventional resources. Microporosity studies have largely focused on siliciclastic mudstones, with limited examples that assess porosity type and distribution in organic-rich calcareous mudstone successions. In this work, a comprehensive porosity characterization study was performed on the organic-rich carbonate-dominated Hanifa Formation of the Jafurah Basin, which is the largest unconventional basin in Saudi Arabia. An extensive experimental program, involving petrographical description, SEM analysis, mineralogical analysis using XRD and QEMSCAN, and geochemistry analysis was employed in order to characterize the samples and analyze the geological origins of the microporosity. The main constituent minerals in this study are calcite (87 wt%) and anhydrite (9 wt%), as well as <1 wt% quartz, illite, pyrite, and dolomite. Total organic carbon reaches up to 5.46 wt %, yielding 5.09 mg HC/g rock (S2), while the free hydrocarbon content (S1) is 5.36 mg/g rock. Type II kerogens characterize the rock samples, and the thermal maturity index is 1.28. The microporosity in Hanifa Formation can be classified into three groups, including framework, solid bitumen, and intraparticle pores. Framework porosity is observed as the main type of microporosity, with solid bitumen representing a subordinate component of the overall porosity. Sheltered pores are also encountered associated with coccoliths tests deposited within the pelagic sediments. Higher degrees of thermal maturity of these sedimentary rocks increase the storage space for the generated hydrocarbon hosted in the solid bitumen. This study introduces an under-explored category of unconventional resources, nominally those that have a carbonate content >85%. Fundamentally, the findings of this study demonstrate that the Hanifa Formation in the Jafurah Basin has the potential for gas exploration and recovery.

Two-Stage Differential Hydrocarbon Enrichment Mode of Maokou Formation in Southeastern Sichuan Basin, Southwestern China

Abstract Sichuan Basin is one of the most potential areas for natural gas exploration and development in China. The Maokou Formation in the basin is one of the important gas-bearing layers in southeastern Sichuan. In recent years, several exploration wells have obtained industrial gas flow in the first member of the Middle Permian Maokou Formation (hereinafter referred to as the Permian Mao-1 member of Maokou Formation), revealing that it may become a new field of oil and gas exploration in Sichuan Basin. Drilling and field survey results show that the shale of Maokou Formation in southeastern Sichuan contains eyeball-shaped limestone. Early studies suggest that the Permian Mao-1 member of Maokou Formation in Sichuan Basin is a set of high-quality carbonate source rocks, but ignoring its oil and gas exploration potential as an unconventional shale reservoir similar to the shale. The enrichment regularity of unconventional natural gas has not been studied from the perspective of source-internal accumulation. And there is a lack of analysis of oil and gas enrichment mode. In this study, we took the Permian Mao-1 member of Maokou Formation in southeastern Sichuan as the target layer. Through macroscopic outcrop observation and geochemical analysis and based on unconventional oil and gas enrichment theory, we carried out a study on natural gas enrichment mode of eyeball-shaped limestone of the Permian Mao-1 member of Maokou Formation in Sichuan Basin. The results show that the hydrocarbon enrichment pattern of the Maokou Formation in southeastern Sichuan is different from the accumulation and occurrence process of common unconventional shale gas reservoirs and conventional carbonate reservoirs. It is a special new hydrocarbon accumulation mode between the above two. According to the difference in the charging time of the hydrocarbon, the background of the reservoiring dynamics, and the occurrence state of oil and gas, we divide the two-stage differential enrichment mode of oil and gas, that is, “early intralayer near-source enrichment” and “late interlayer pressure relief adjustment.”

Producible fluid oil saturations of the Upper Cretaceous unconventional carbonate plays, northern Arabian plate

Producible fluid oil saturations of the Upper Cretaceous unconventional carbonate plays, northern Arabian plate

Characterization of reservoirs, fluids, and productions from the Ordovician carbonate condensate field in the Tarim Basin, northwestern China

The TZ-No1 gas field in the Tarim Basin is the largest condensate field in China; however, it has not developed efficiently because of low and unpredictable production during the past 20 yr. Cores, logging interpretation, seismic descriptions, fluid properties, and production data indicate that this Ordovician carbonate field is different from conventional stratigraphic oil and gas fields as follows: (1) the hydrocarbon-bearing area covers a large region of 2000 km2; (2) matrix reservoirs have low porosity ( 20% per year). An examination of the carbonate reservoir and hydrocarbon accumulation history suggests that this large-scale stratigraphic accumulation formed during hydrocarbon emplacement in the early Paleozoic, with the reservoirs gradually evolving into tight reservoirs as a result of intense diagenesis. Variable amounts of Neogene gas charged the tight carbonate reservoirs and formed unconventional accumulations. The TZ-No1 gas field is characterized by a strongly heterogeneous tight matrix reservoir with a superimposed fracture-cave reservoir and a complicated unconventional fluid distribution, which provides insights into the exploitation challenges of unconventional carbonate resources.

An experimental study to reduce the breakdown pressure of the unconventional carbonate rock by cyclic injection of thermochemical fluids

Commercial production from unconventional reservoirs needs massive fracturing operations. Therefore, long horizontal wells are drilled, and multi-stage fractures are created to achieve the desirable production rates from these reservoirs. One common and major problem in most of the unconventional reservoirs is the high breakdown pressure due to the reservoir tightness. When fracturing these types of rocks, the hydraulic fracturing operation becomes much more challenging and difficult. In some scenarios reaches to the maximum pumping capacity without generating any fractures. In this study, a new approach to reduce the breakdown pressure of tight rocks is introduced and compared with the conventional method of fracturing. The new method incorporates the injection of thermochemical fluid in a series of cycles to create micro- and macro-fractures. The cyclic experiments performed in this study were concluded with the recording of breakdown pressure in each case. The post-treatment analysis using medical Computerized Tomography (CT) showed that multiple fractures were created due to the pressure pulse created in the thermochemical reaction. Results showed that the breakdown pressure of the rock decreases with the increasing number of cycles. The proposed method of cyclic thermochemical fracturing reduced the breakdown pressure by 33% in one-cycle, 41% in two-cycles, 53.5% in three-cycles, and 69% in four-cycles, when compared with conventional method of fracturing. An empirical relationship is also presented between the number of cycles of thermochemical fluid injection and the breakdown pressure of the rock.

The Three Forks playa lake depositional model: Implications for characterization and development of an unconventional carbonate play

The Upper Devonian Three Forks Formation of the Williston Basin is an important reservoir interval in the Bakken petroleum system, with estimates suggesting greater than 3.7 billion bbl of recoverable oil. Detailed stratigraphic analyses are sparse, but current studies propose shallow marine, tidal flat, or coastal sabkha environments for its deposition. Based on stratigraphic, sedimentological, and petrographic analyses of 28 cores, we infer that the Three Forks Formation was deposited in a continental setting with little to no marine influence. The setting was subaerial to subaqueous environments comparable to those found in playa lake systems or continental sabkhas. Late Devonian paleography and tectonics provided the isolation and slow subsidence of the Williston Basin that led to the accumulation of the Three Forks Formation in a hot and arid climate. Occasional floods were responsible for the deposition of the terrigenous sediments, debrite-like deposits, reworking, bedforms, scouring, and erosional surfaces. Flood waters collected in ephemeral lakes and ponds evaporated, resulting in the deposition of subaqueous dolomite, anhydrite, and even halite. The ponds and lakes progressively evaporated and contracted until they eventually dried out. The drying is characterized by dewatering structures, subaerially exposed and transported sediments with ripples, scour surfaces, evaporite cemented surfaces, evaporite removal breccias, halite pseudomorphs, and a variety of cracks. Vertical successions record an upward trend of increasing proportions of subaqueous facies, indicating a transition from arid to relatively less arid climatic conditions during Three Forks deposition. This depositional system resulted in the accumulation of a complex mosaic of lithologies composed of different proportions and textures of silt-sized detrital dolomite and quartz, clay, and evaporites in patchy to bull’s-eye configurations. This depositional model provides a coherent understanding of the existing depositional lithofacies and their petrophysical and geomechanical properties and provides the background for the prediction of their lateral distribution from wire-line logs.

A comparison of the relationship between measured acoustic response and porosity in carbonates across different geologic periods, depositional basins, and with variable mineral composition

Recent work has shown that there is a predictable inverse relationship between laboratory-measured sonic velocity response and porosity in carbonates, which can be reasonably approximated using the empirical Wyllie time-average equation (WTA). The relationship was initially identified in late Cretaceous to Cenozoic age samples collected from the Great Bahama Bank and the Maiella Platform, an exhumed Cretaceous carbonate platform in Italy. We have compared older carbonate samples from different basins and different geologic ages to determine the applicability of this relationship and subsequent correlations to key petrophysical properties to other carbonate basins and other geologic time periods. The data set used for the comparison shows this relationship to be relatively consistent in other depositional basins (Michigan Basin, Paradox Basin) and with samples from older geologic periods (Pennsylvanian, Ordovician, and Mississippian). However, this basic relationship is also observed to vary significantly within a reservoir system and within a depositional basin in samples from different geologic periods (e.g., Silurian- versus Ordovician-age rocks in the Michigan Basin). Although the empirical WTA can generally be applied as a first-order estimate across a wide range of sample ages in carbonates, limited data suggest the relationship between velocity and porosity to be moderately more complex. For instance, in unconventional carbonate reservoirs characterized by predominantly micro- to nanoscale porosity, it is observed that the WTA should be applied as an upper data boundary. In addition, this study has shown that the relationship to the dominant pore type is less direct than in a macropore system in which it can be assumed that the dominant pore type also has the greatest effect on the effective permeability.

Facies-independent reservoir characterization of the micropore-dominated Word field (Edwards Formation), Lavaca County, Texas

Micropore-dominated carbonate reservoirs remain challenging for accurate hydrocarbon evaluation and production as conventional reservoir models using depositional textures and petrophysical properties to distribute porosity and permeability cannot be applied. Nevertheless, understanding the distribution of pore systems and predicting the fluid flow behavior of microporous reservoirs is fundamental as micropores constitute a significant percentage of the total porosity and storage capacity. We present the results from an integrated study on the producing micropore-dominated Word Field characterized by a facies independent, diagenetically controlled pore system that approaches 100% microporosity. Four cored wells through the Albian Edwards Formation were described and correlated using stacking patterns and vertical facies trends; pore type characterization was done through thin section petrography, routine core analyses, SEM and MICP data. This study is an example of a permeable reservoir in which intergrain pores are cemented during burial diagenesis and micropores, being more resistant to cementation, remain open to depths greater than 4000 m (13,000 ft). A unique relationship exists between porosity, permeability, median pore-throat size and microcrystalline textures, independent of facies and fabrics. Cumulative gas production data show there is a correlation between the total porosity and the structural position of the wells – wells high on the structure have the highest production. We demonstrate that an equally well-connected micropore network exists in mud-dominated rocks via the matrix, and via grain-to-grain contacts in grain-dominated rocks. The here described intragrain micropore network through grain-to-grain contacts in cemented grainstones is a new carbonate flow path that will likely become more important as more unconventional carbonate reservoirs are explored.

Technology Update: Completion Methods Analyzed in Two US Unconventional Plays

Technology Update The information in the article is based on paper SPE 176984, which was presented at the 2015 SPE Asia Pacific Unconventional Resources Conference and Exhibition in Brisbane, Australia, 9–11 November. An operator in the United States midcontinent region systematically analyzed different completion technologies and identified openhole multistage (OHMS) systems as a more cost-effective method than the cemented casing plug-and-perf (CCPP) techniques, used on previous wells, for increasing production and reducing development costs. The operator holds one of the largest acreage positions in the region and in 2014 had operated or participated in approximately 170 horizontal wells. The operator’s development focused mainly on the Mississippian Lime play in northern Oklahoma and the Marmaton play in the Oklahoma and Texas Panhandles. Each carbonate resource play required a thorough evaluation to assess the unique geologic characteristics and thoughtful application of technology to unlock significant amounts of previously untapped oil and gas deposits. These plays are composed of a mix of unconventional shale, carbonate, and sandstone plays. When developing its assets, the operator focused on creating a productive well, then on improving production and well cost. The steps taken by the operator included the following: comparing different completion methods analyzing completion costs implementing new technology to improve completions studying microseismic data to confirm assumptions and fine-tune completion design conducting tracer analysis to ensure all stages were contributing to production Lessons learned from each well were applied to future wells, and the operator realized further cost savings as it continued development of the region using OHMS completion systems. These cost reductions were achieved while preserving the estimated ultimate recovery (EUR) of the assets, increasing the economic viability of the operations. Completion Methods Compared The first objective was to determine which major completion function had the most effect on production and then on cost. Completion equipment is a major function of this aspect, and currently there are two main completion methods being used in the two plays: OHMS completion systems and CCPP methods. The main difference between OHMS and CCPP systems is when the liner is picked up and run into the lateral section (Snyder and Seale 2011). In OHMS completion systems, the lateral section is left as uncemented, and fracture ports and isolation packers are run into the well as part of the liner. The well is stimulated in one continuous pumping operation, using size-specific actuation balls to open the fracture ports and provide isolation inside the liner between stages. In CCPP completions, a liner is run into the wellbore and cemented in place. The cement provides annular isolation, while a series of bridge plugs provide isolation inside the liner between stages. Several trips are required in and out of the wellbore to shoot perforation clusters in the liner and set bridge plugs for each stage.

Algal–microbial carbonates of the Namibe Basin (Albian, Angola): implications for microbial carbonate mound development in the South Atlantic

Albian carbonate reservoirs are prominent in the subsurface of the South Atlantic. Equivalent exposures in southern Angola (Benguela and Namibe basins) have received relatively little detailed sedimentological work. In the Namibe Basin, carbonates form metre-thick beds interbedded with shallow-marine and continental alluvial fan siliciclastics. Characteristic carbonate mounds (≤5 m high, 1–2 m in diameter) rise above a basal carbonate bed, which consists of oncoid–peloidal rud-grainstones with oysters and echinoderms. Thrombolite mound microfacies include red algae and microbial–algal crusts. The microfacies are marine, and compare with documented occurrences of algal–microbial–oncoidal textures in Albian carbonates of the Congo and Angola. Burial processes dominated diagenesis and have reset carbonate geochemistry from marine values, with the probable exception of Mg concentrations. Up to 22% of primary (intergranular) and secondary (microporosity, mouldic, vuggy, fracture) porosity developed as a consequence of important dissolution and partial cementation. Two depositional models for the localized mound occurrence are discussed: (1) marine ingression into a coastal embayment and the formation of shallow-water microbial bioherms; and (2) a submarine groundwater spring discharging in coastal areas downdip from alluvial siliciclastics. Marine fauna, similarity with marine Albian strata elsewhere and a partly preserved marine Mg geochemical signature favour a marine ingression. Environmental conditions were likely to have been stressed on account of the siliciclastic input, variable salinity and elevated nutrients, all of which are consistent with the observed microfacies. A submarine spring is conceptually feasible, but is considered to be less likely owing to the absence of a clear meteoric signature and the low likelihood of bicarbonate-rich groundwater in the region. Using the discussion of depositional models for the studied outcrop, and incorporating a literature review, the study proposes a set of criteria to distinguish various marine and non-marine carbonate mounds in the subsurface. The most diagnostic criteria are: (1) marine or continental fauna; (2) sediment geochemistry, in particular Mg, Sr, and δ 13 C and δ 18 O isotopes where preserved through diagenesis; and (3) carbonate fabrics, such as crystalline shrubs, that are diagnostic of thermogenic continental mounds. The scale of geobodies and the mineralogy of mounds can sometimes be used as additional criteria. This set of criteria can help exploration and production geologists who need to devise exploration and development strategies in unconventional carbonate reservoirs of the South Atlantic and other rift basins.

Proppant Fracture for Unconventional Carbonate Source Rock in Saudi Arabia

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17765, “First Successful Proppant Fracture for Unconventional Carbonate Source Rock in Saudi Arabia,” by Nayef Ibrahim Al-Mulhim, SPE, Ali Hussein Al-Saihati, SPE, Ahmed M. Hakami, SPE, Moataz Al-Harbi, SPE, and Khalid Saeed Asiri, SPE, Saudi Aramco, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. A type of unconventional play currently being evaluated is a carbonate source rock with nanodarcy permeability and very low porosity. This paper will discuss the hydraulic-fracturing- stimulation design, execution, and evaluation for the first successful proppant-fracturing treatment in an unconventional carbonate source rock in Saudi Arabia. The successful two-stage treatment proved that proppant-fracturing techniques could be used to stimulate carbonate formations after modifying the stimulation design (specifically, the perforation strategy, fracturing fluids, and proppant type). Introduction The operator has embarked on an exploration-and-appraisal project to assess unconventional-resource potential in three geographic areas: northwest, South Ghawar, and East Ghawar. Hydraulic-fracturing techniques will be used to enhance production by connecting natural fissures and creating high-connectivity pathways through which gas can flow into the well. The initial focus is in the northwest and in the area of Ghawar. Initial knowledge building from similar plays in North America is being supplemented with internal technical studies and research programs to help solve geological and engineering challenges unique to Saudi Arabia and to locate specific wells planned for 2014. Acid vs. Proppant Fracturing The operator has used mainly acid fracturing and matrix acidizing to increase production rates from carbonate formations in conventional gas fields, while proppant fracturing was used predominantly in sandstone formations. This methodology, coupled with the fact that all previous attempts to stimulate carbonate formations in Saudi Arabia resulted in premature screenouts after only 10% of the proppant had been placed in the formation, clearly demonstrates the significance of the first successful proppant-fracturing treatment in an unconventional carbonate source rock in Saudi Arabia. Jafurah Basin Source Rocks The Jurassic sediments being targeted in the Jafurah basin as unconventional reservoirs are carbonate source rocks within the Tuwaiq Mountain, Hanifa, and locally basal Jubaila formations (please see the complete paper for a detailed geological description). The H-1 well is the first well drilled on a seismic anomaly, and it encountered a thick organicrich Jurassic source rock. The thick sequence of source rock in the H-1 well, as well as other areas within the basin, may suggest the possibility of a commercially viable unconventional play. As a followup to the drilling of the H-1 well, a geophysical forward-modeling project was initiated to investigate the cause of the seismic-amplitude anomaly in the Jafurah basin. The study revealed that the formation encountered in the H-1 well has an overall lower acoustic impedance, which appears to be the result of its high total organic content. Drilling and Coring The H-2 well, east of the giant Ghawar field, was drilled to evaluate several Jurassic source-rock targets. The well was completed with 4½-in. tubing, a 7-in. liner with a 7-in. permanent packer, and a 25-ft sealbore receptacle. The tubing and annulus were displaced with 65-lbm/ft3 brine. The well was designed to be re-entered for horizontal sidetracking. Five cores were cut for laboratory testing and analysis. Acid-solubility tests were performed on the core-plug samples to determine their solubility in hydrochloric acid (HCl). X-ray-diffraction analysis was performed on four core samples before and after the acid-solubility tests, showing that the four samples analyzed consisted mainly of calcite with smaller fractions of dolomite, quartz, anhydrite, pyrite, and clays. Perforation-Design Strategy Deep-penetrating charges were used in Well H-2, in conjunction with underbalanced perforating to minimize perforation damage and ensure clean perforations. In addition, 3,000 gal of 15% HCl was pumped as a preflush before pumping the pad in each stimulation treatment to further aid in removal of debris from the perforation tunnels.

Hydrocarbon Accumulation Conditions of Ordovician Carbonate in Tarim Basin

Abstract:Based on comprehensive analysis of reservoir‐forming conditions, the diversity of reservoir and the difference of multistage hydrocarbon charge are the key factors for the carbonate hydrocarbon accumulation of the Ordovician in the Tarim Basin. Undergone four major deposition‐tectonic cycles, the Ordovician carbonate formed a stable structural framework with huge uplifts, in which are developed reservoirs of the reef‐bank type and unconformity type, and resulted in multistage hydrocarbon charge and accumulation during the Caledonian, Late Hercynian and Late Himalayan. With low matrix porosity and permeability of the Ordovician carbonate, the secondary solution pores and caverns serve as the main reservoir space. The polyphase tectonic movements formed unconformity reservoirs widely distributed around the paleo‐uplifts; and the reef‐bank reservoir is controlled by two kinds of sedimentary facies belts, namely the steep slope and gentle slope. The unconventional carbonate pool is characterized by extensive distribution, no obvious edge water or bottom water, complicated oil/gas/water relations and severe heterogeneity controlled by reservoirs. The low porosity and low permeability reservoir together with multi‐period hydrocarbon accumulation resulted in the difference and complex of the distribution and production of oil/gas/water. The distribution of hydrocarbon is controlled by the temporal‐spatial relation between revolution of source rocks and paleo‐uplifts. The heterogenetic carbonate reservoir and late‐stage gas charge are the main factors making the oil/ gas phase complicated. The slope areas of the paleo‐uplifts formed in the Paleozoic are the main carbonate exploration directions based on comprehensive evaluation. The Ordovician of the northern slope of the Tazhong uplift, Lunnan and its periphery areas are practical exploration fields. The Yengimahalla‐Hanikatam and Markit slopes are the important replacement targets for carbonate exploration. Gucheng, Tadong, the deep layers of Cambrian dolomite in the Lunnan and Tazhong‐Bachu areas are favorable directions for research and risk exploration.