Chemical Characteristics of Ordovician Formation Water and Its Relationship with Hydrocarbons in Halahatang Depression, Tarim Basin, NW China

: The chemical characteristics of Ordovician formation water and its relationship with hydrocarbons in the Halahatang depression (Tabei Uplift, Tarim Basin, NW China) were analyzed on the basis of the detailed formation water test data. The formation water in the Halahatang depression can be characterized as CaCl 2 type with high total dissolved solids (TDS) generally. The TDS concentration has a weak negative relationship with the depth, and is above 200 g/L in the North Region (north of the pinch-out line), then gradually decreases to the south, but is still greater than 50 g/L. The ion-proportionality coefﬁcients of formation water, including the sodium-chlorine coefﬁcient, desulfurization coefﬁcient and metamorphic coefﬁcient, reﬂect that the present strata are well sealed and had once experienced strong water-rock interactions. Furthermore, the source and evolution of the formation water presents a closed relationship with the hydrocarbon accumulation. The meteoric source of the formation water indicates the denuding by the Ordovician formation and the damage from the previous oil and gas reservoirs. The reservoir quality was also improved due to the strong karstiﬁcation during the denudation, which was beneﬁcial for hydrocarbon accumulation. The distribution of the TDS concentration is controlled by the caprock (Sangtamu Formation) and the high salinity ﬂuids from overlying strata and adjacent regions. A geological model was established, the high salinity ﬂuids penetrated the Ordovician strata resulting in the TDS increases in the northern part. Whereas, the South Region (south of the pinch-out line) was less affected due to the shielding layer of the O 3 s. The favorable preservation conditions reﬂected by the high TDS and ion-proportionality coefﬁcients correspond to the stable subsidence of strata since the Triassic era, the oil and gas reservoirs formed in the Himalayan can be preserved.


Introduction
As a result of the evaporation concentration, water-rock interactions and fluids flowing and mixing, the chemical characteristics of formation water can indicate the hydrogeochemical environment and the activities of the fluids of the basin [1,2]. In common practice, the TDS, water types, ion-proportionality coefficients and stable isotopes of formation water are used as indicators of the degree of water-rock interactions, the sealing condition of strata and the migration, accumulation and preservation of oil and gas [3][4][5][6].
Carbonate reservoir generated from paleo-karstification has a close relation with the hydrogeological process of the basin [7,8]. Meanwhile, the chemical and isotopic components of formation water is influenced by the water-rock interactions and the charging of hy-drocarbons [9,10]. Thus, studying the chemical characteristics of formation water is of great significance to reveal the carbonate reservoirs' alteration and hydrocarbon accumulation.
Tarim Basin is the major marine sedimentary basin in China and the carbonate reservoir of Palaeozoic is the main petroleum production layer. In recent years, carbonate oil and gas pools have been discovered successively in the Tabei Uplift of the basin, such as Tahe Oilfield and Lunnan Oilfield. Studies have been completed, including the element and isotopic compositions, the spatial distribution characteristics and the source of formation water [11][12][13][14][15][16][17], the influence of formation water on the reservoir's physical properties and the relationship between the hydrochemical characteristics and hydrocarbon accumulation [11,[18][19][20][21].
However, these investigations in the Halahatang depression are scarce. This paper analyzed the chemical characteristics and established the source and evolution model of Ordovician formation water in the Halahatang depression. The paper discusses the indicative significance of the hydrochemical characteristics to oil and gas accumulation. These results can provide references for the further study of oil and gas exploration and development in the study area.

Geological Setting
The Tarim Basin, in NW China (Figure 1a), is a large superimposed composite basin composed of the Paleozoic marine craton sedimentary and the Mesozoic-Cenozoic continental sedimentary. The basin has undergone a complex structural evolution process, formed the present tectonic framework, include the Kuqa Depression, Tabei Uplift, Northern Depression, Central Uplift, Southwest Depression, Southeast Uplift and Southeast Depression (Figure 1b) [22][23][24]. The Tabei Uplift, located in the north of Tarim Basin (Figure 1b, yellow area), is a long-term inherited paleo-uplift developed on the pre-Sinian metamorphic basement. The evolution of the Tabei Uplift can be summarized as the basement formation stage in pre-Sinian, the paleo-uplift formation stage between Sinian and Devonian, faults and fault-blocks mainly formed from Carboniferous to Triassic, followed by continuous subsidence ranging from the Jurassic to Paleogene periods and thereafter the rapid subsidence stage from the Neogene to Quaternary periods [25,26].
Halahatang depression is located in the central part of the Tabei Uplift, surrounded by the Yingmaili low uplift, the Manjiaer depression, the Lunnan low uplift and the Luntai uplift ( Figure 1c). The whole exploration area is about 4369 km 2 [27]. As the target area for oil and gas migration, a large volume of petroleum has been found in the Halahatang depression.
Detailed geological characteristics of the Halahatang depression had been summarized in numerous publications [25,28,29]. In brief, the lower Paleozoic in the study area consists of the Silurian, Ordovician and Cambrian strata. The Silurian mainly consists of sandstone and mudstone. The Sangtamu formation (O 3 s) of the Upper Ordovician is primarily composed of mudstone, lime mudstone and muddy limestone, which can be regarded as caprock for the carbonate reservoirs. Bioclastic limestone and arenaceous limestone are the main compositions of the Middle Ordovician Yijianfang formation (O 2 yj). The Yingshan formation (O 1−2 y) mainly contains micritic limestone, arenaceous limestone, and partly dolomite. Both the Yijianfang and Yingshan formations are the major karst reservoirs. The petroleum produced in these layers includes condensate oils, light oils, normal oils, heavy oils and ultra-heavy oils. Under the complicated tectonic events from the Caledonian to the Himalayas' orogeny, the upper Ordovician eroded and pinched out successively from the north to south, generating the angular unconformities and parallel unconformities among the Silurian and Ordovician strata (Figure 1d). The most intense uplift and denudation occurred after the deposition of the Sangtamu formation. In addition, the early-middle Caledonian tectonic movements formed a series of large strike-slip faults, showing an "X" type combination in the plane [30], and continued to be active until the Triassic period. These unconformities and strike-slip faults play an important role in the evolution of formation water and the accumulation of hydrocarbon, for providing conditions for the geofluids activities.
The Cambrian-Ordovician in the Tabei Uplift experienced three stages of oil and gas charging: Oil charging in the Late Caledonian-Early Hercynian; Oil charging in the Late Hercynian-Indosinian; Oil and gas charging in the Himalayan [29,[31][32][33][34]. Oil reservoirs formed in the Late Caledonian-Early Hercynian were destroyed by multi-stage tectonic movements, part of the paleo-oil reservoir was preserved, but the oil was degraded into heavy oil. Late Hercynian-Indosinian was the major stage of the oil reservoirs' generation. A large quantity of hydrocarbons generated in the Cambrian source rocks then migrated through the faults into the Ordovician fractured-vuggy reservoirs, forming large-scale accumulations. Due to the varying degree of the tectonic movements, oil reservoirs in north of the Tabei uplift were degraded into heavy oil while they remained well preserved in the south and mainly contained medium oil. Light oil and dry gas generated in the Himalayan, mainly charging from south to north and well preserved.

Materials and Methods
A total of 200 items of formation water analysis data from 92 wells were selected after data screening. The chemical characteristics of formation water might be influenced by the acidizing fluids and fracturing fluids during the development and production process of oil and gas. This type of formation water cannot truly reflect the hydrological environment of the strata. A series of feasible test data screening schemes for formation water have been established in different regions [35]. In this paper, the test data of formation water of Ordovician in the Halahatang depression are screened in combination with the previous screening schemes and the development and production process of oil and gas. The criteria for screening data include: (1) The imbalance between cations and anions; (2) Too low or too high TDS concentration; (3) Too high or too low pH; (4) The content of K + is higher than that of Na + .

Chemical Compositions
The TDS of Ordovician formation water in the Halahatang depression ranges from 59.7 g/L to 270.6 g/L, with an average of 178.5 g/L, which can be defined as brine (TDS > 35 g/L) according to the salinity classification [10]. The (Na + + K + ), Ca 2+ , Mg 2+ , HCO 3 − , SO 4 2− and Cl − are the major ions in the formation water. The (Na + + K + ) is dominated by cations, but in some samples, Ca 2+ can account for more than 50% of the cations, the Mg 2+ content being the lowest. Cl − is the major anion (accounting for 98%) of the anion components, controlling the TDS of the formation water, followed by SO 4 2− and HCO 3 − . The pH of the formation water ranges from 4.2 to 7.9 (Avg: 6.2). The formation water is of a CaCl 2 type on the whole.
The TDS of the formation water in the Halahatang depression has a weak negative correlation with depth (Depth above 6500 m: depth = −5.16 TDS + 6999.30 R 2 = 0.49; Depth below 6500 m: depth = −2.08 TDS + 7234.50 R 2 = 0.34) (Figure 2). Besides, the TDS of Ordovician formation water in Halahatang depression is higher in the North Region but lower in the South Region ( Figure 3). North of the pinch-out line of O 3 s in the study area, the TDS is mostly higher than 200 g/L and gradually decreases to the south, but is still greater than 50 g/L.

Ion-Proportionality Coefficients
The ion-proportionality coefficients, including sodium-chlorine coefficient (γ Na + /γ Cl − ), desulfurization coefficient (γ SO 4 2− × 100/γ Cl − ) and metamorphic coefficient [(γ Cl − − γ Na + )/γ Mg 2+ ], are mainly used to reveal the underground hydrological environment and the intensity of water-rock interactions [6,36,37]. The sodium-chlorine coefficient can reflect the sealing property of the formation and the degree of water-rock interactions (bounded by 0.85) [38]. The value less than 0.85 indicates that the strata have good sealing performance and experienced strong water-rock interactions. The desulfurization coefficient can indicate the degree of desulfurization, which in turn reflects the formation environment [11]. It is generally very low in the sealed environment, and greater than three while the formation has a certain degree of open or totally open condition. The metamorphic coefficient can also demonstrate the intensity of water-rock interactions [36]. The higher the metamorphism coefficient is, the stronger the water-rock interactions are.
In the Halahatang depression, the O 2 yj and O 1−2 y samples in both the North and South Regions have a sodium-chloride coefficient between 0.144-0.873 and 0.211-0.782, respectively. The desulfurization coefficient ranges from 0.011 to 1.248 and 0.135 to 0.866, respec-tively. The metamorphism coefficient distributes between 5.655-60.329 and 5.143-36.404, respectively. The average sodium-chloride coefficient, desulfurization coefficient and metamorphism coefficient are all less than 0.85, 1 and greater than 10, respectively (Table 1). These results reveal that the Ordovician strata have good preservation conditions. Despite being influenced by the meteoric water in early stage, the formation water still experienced strong water-rock interactions in the process of deep burying.

Source and Evolution of the Ordovician Formation Water
Formation water in sedimentary basins generally originates from meteoric water, river water or seawater, and would be influenced by the evaporation concentration, mixing of different water and water-rock interactions in the evolution of the strata [1,17].

The Source of Formation Water
The evolution process of the Halahatang depression is similar to those of the Lunnan buried hill anticline: both had experienced multiple periods of tectonic movements. In the Early Hercynian, Halahatang was part of the western slope of the Lunnan large anticline. The lower structural layer of Cambrian-Ordovician has similar tectonic features to the Lunnan low-uplift. In the Late Paleozoic-Mesozoic, the Halahatang area gradually evolved into a structural depression [25]. The previous works from the Tahe area, which is located on the slope from the Halahatang depression to the Lunnan uplift (see Figure 1c) can provide references to this study.
By collecting 258 calcite samples from the karst fracture-cavity in the Ordovician carbonate rocks in the Tahe area [14,16,18,39,40] and 107 calcite samples from the karst fracture-cavity in the Ordovician carbonate rocks in the Halahatang area [41][42][43], the distribution of δ 13 C and δ 18 O are similar. The δ 13 C and the δ 18 O mainly range from −13.74‰ to 9.06‰ (Avg: −10.17‰) and from−17.54‰ to −3.05‰ (Avg: −10.34‰), respectively ( Figure 4). The positive correlation between the δ 13 C and the δ 18 O and the value of the stable isotopes that are widely distributed reflect the complicated diagenesis in the Halahatang depression. Compared with the carbonate background values of δ 13 C (−1.58-0.12‰) and δ 18 O (−6.01-−6.52‰) in the Halahatang area [42], there is an obvious negative shift in most of the data. The value of δ 13 C and δ 18 O in a meteoric water environment generally show a strong negative and a shift to positive when it was related to seawater [44,45]. When these two fluids were mixed, the δ 13 C and δ 18 O distribute between the value of meteoric water and seawater. In the buried diagenetic environment, the value of δ 13 C is stable or shifts to positive and the δ 18 O shifts to strong negative [46]. Furthermore, influenced by the hydrothermal fluids show a more substantial negative of δ 18 O [43]. Therefore, it can be concluded that the genesis of calcite in the Halahatang depression was mainly related to the influence of paleo-meteoric water, partly due to the influence of seawater, mixed fluids and the burial environment, and the hydrothermal fluid also had a certain degree of effect on the diagenesis process ( Figure 4).  [14,15,18,38,39,[41][42][43][44][45].
In addition, the strontium isotopes in the Tahe area have the characteristic of a crust source [39]. Moreover, the fit line of hydrogen and oxygen isotopes of formation water in the Tahe and Lunnan areas intersect with the global precipitation line, after extension [13,14,21]. These results further proved that the primary source of formation water is paleo-meteoric water.

Water-Rock Interactions
The Piper diagram mainly uses the relative equivalent concentration percentage of the major cations and anions to represent the properties of formation water [47], which can reveal the sources of the dissolved constituents in waters without artificial influence.
The Ordovician formation water in the Halahatang depression can be divided into two types ( Figure 5). The type I includes Cl-Na type and Cl-Na·Ca type, which are dominant in water samples. Type II contains Cl-Ca·Na type and Cl-Ca type. These two types of water are typical of brines from deep reservoirs in sedimentary basins [10], distributed in both the North and South Regions ( Figure 5). This indicates that the present formation water experienced strong water-rock interactions in the Halahatang depression, which corresponds to the ion-proportionality coefficients.

Relation between Formation Water and Oil and Gas
Formation water has both modified and destructive effects on oil and gas reservoirs. The solution pores formed under the dissolution of carbonate rock by formation water, which was conducive to generate oil and gas reservoirs [48,49]. However, meteoric water entering the formation will damage the oil and gas reservoir [50]. In addition, the hydrochemical parameters, such as the TDS and ion-proportionality coefficients, can reflect the hydrogeological environment to a certain extent [51]. Thus, we can further determine whether it is conducive to the accumulation and preservation of hydrocarbons.

Effect of Formation Water on Oil and Gas Accumulation
The orogenic movements in the Caledonian and Hercynian periods played an essential role in the generation and improvement of reservoirs. Because of the denudation of strata and the dissolution of carbonate reservoirs by meteoric water, the Ordovician strata in the Halahatang depression mainly developed quasi-syngenetic karst, weathering crust karst and buried karstification [28,52]. These karstification processes made the Ordovician carbonate strata become favorable reservoirs. The strike-slip faults major formed in the Middle Caledonian period provided the migration channel of fluids, which further promotes the karstification. Besides, the acid water migrated with petroleum and hydrothermal fluid were also suggested as a source of improved reservoir quality.
However, the tectonic uplift also has a significantly destructive effect on oil and gas reservoirs. Because of the Caledonian and Hercynian tectonic uplift, a mass of microorganisms and sufficient oxygen carried by meteoric water entered the oil and gas reservoirs. This denudation promoted biodegradation together with water washing of crude oil, causing further damage in the pools. The widespread presence of heavy oil and asphalt in the North Region demonstrated this destructive effect. Although the biodegradation usually masks the development of water washing [53], the tectonic evolution and the source of formation water in Halahatang depression were sufficient to prove the effect of water washing on crude oil.
Due to the different intensities of tectonic evolution in the North and South Regions, the degree of destruction of oil and gas reservoirs is also different ( Figure 6). The strata in the North Region were subjected to more intense uplift and denudation. Oil and gas reservoirs formed in the early stage were basically destroyed in the process of tectonic evolution and the crude oil degraded into heavy oil and asphalt. However, the strata in the South Region were less affected and the paleo-reservoirs partly preserved. Since the Triassic period, the strata subsided stably and were less influenced by destructive structures. Oil and gas generated in the later stage entered the reservoir and mixed with the pre-existing oils, forming the present oil and gas reservoir [29,32,33].

Indication of Hydrochemistry Characteristics to Oil and Gas
The TDS has a certain indication to the migration of oil and gas. In many basins, the increasing TDS corresponded to the direction of hydrocarbon migration [54][55][56][57]. However, this is not applicable in all regions. In addition, the ion-proportionality coefficients of formation water can reflect the hydrological environment of underground strata, which can determine whether the strata are conducive to oil and gas accumulation and preservation.
The geochemical characteristics of crude oil in the Halahatang depression show that oil and gas migrated from south to north and northeast [25,32,58,59], which is consistent with the increasing direction of the TDS. However, the distribution of the TDS of formation water in Halahatang depression is mainly controlled by the caprock (Sangtamu Formation) and the high salinity fluids from overlying strata and adjacent regions.
The influence of halite dissolution on brine salinity of formation water in sedimentary basin has been discussed [60,61]. Previous works on the Tarim basin also have concluded that the formation water in the Lunnan low uplift and the Tahe area was influenced by the dissolution of halite in the overlying strata [11,17,20,21,62,63]. Gypsum-salt is distributed widely in the Carboniferous strata in the Halahatang depression (Figure 7), which is an effective source of halite. It can be seen that the Carboniferous (gypsum-salt layer) formation water has high TDS (area III) but the TDS of the Ordovician formation water in the South Region is relatively low (area I) ( Figure 8). However, the TDS data of the North Region Ordovician formation water (area II) are close to those of Carboniferous, indicating a certain correlation (Figure 8).
The fluids that had leached the halite from the overlying strata entered the Ordovician strata along the unconformities and strike-slip faults. When mixed with connate water it resulted in the salinity increase of formation water in the Ordovician ( Figure 9). However, due to the existence of the mudstone shielding layer of O 3 s, the high salinity fluids cannot enter the Ordovician strata directly. The diffusion of the solute from the high salinity fluids gradually weaken to the south, causing the TDS to be lower than that in the North Region ( Figure 9).   Nonetheless, the CaCl 2 type formation water with high TDS and reductive ionproportionality coefficients on the whole reflect the good preservation conditions of the Ordovician strata. After the Caledonian-Hercynian tectonic uplift, the overlying strata settled steadily onto the Ordovician strata, leading to the gradual improvement of preservation conditions. The Ordovician strata altered by karstification can be regarded as favorable reservoirs and the strike-slip faults provided the migration pathway for hydrocarbon. Oil formed in the Himalayan entered the reservoir and mixing with heavy oils that had been destroyed earlier, forming the present oil and gas reservoirs.

Conclusions
(1) The formation water in the Halahatang depression is CaCl 2 type with high salinity and the TDS decreases with the depth. High salinity fluids entered the Ordovician strata and the distribution of mudstone barrier layer of O 3 s accounted for the TDS distribution. The ion-proportionality coefficients show that the present Ordovician strata are well sealed and had experienced strong water-rock interactions; (2) The formation water mainly originated from paleo-meteoric water, mixed or re-placed with seawater and was affected by hydrothermal activities to a certain extent. With the stable sedimentation of overlaying strata, the sealing conditions and the water-rock interactions became stronger. Reflected in the Piper diagram, the formation water of the Ordovician strata in the Halahatang depression is typical of brine from deep reservoirs in sedimentary basins that experienced strong water-rock interactions; (3) Formation water has both positive and destructive effects on oil and gas reservoirs.
The increasing direction of the TDS is consistent with the direction of hydrocarbon migration, but the caprock and high salinity fluids from overlying strata and adjacent regions controlled the TDS distribution. The high TDS and reductive ionproportionality coefficients reveal that the sealing condition of the Ordovician strata in the Halahatang depression is beneficial to the accumulation and preservation of oil and gas reservoirs.