Regularities in formation of stressed state in roof rocks of mined-out space during development stage

Formation of the stress-and-strain state of the rock mass in the roof of mined coal seam depends on the development of the mined-out space. It is believed that the coal seam is located deep enough and it can be assumed that the effect of the daylight surface on its condition can be neglected. In this case, the solution is based on the analytical approach using methods of the complex variable theory and it is reduced to the construction of a single permission analytical function. The paper reviews the evolution of the deformation processes in development of the mined-out space in presence of a hard-to-collapse elastic roof, which is capable of sinking smoothly over time, without sudden caving on the landings on the floor. A particular attention is paid to the phase when the roof and the floor touch each other, i.e. the roof caving, starting from the first touching and up to its complete caving. In this case, two sections of the hanging roof are formed, that are gradually reducing in length as the dimensions of the mined-out space increase. The area of roof caving is progressively increasing, and the vertical compressive stresses at the boundary are gradually rising, tending to reach the initial vertical pressure at the depth of the formation before the start of its mining. Tension zones relative to the horizontal and vertical stresses are identified, that are attributed to the areas of roof hang-up, which may determine the location of zones with higher methane and formation water permeability, both in the rocks between the seams and in the coal seam.

Geochemical Evaluation of Formation Water, Mauddud Reservoir, Khabbaz Oilfield, Kirkuk Area, Northern Iraq

In this study, formation-water samples were collected by NOC Staff, during drilling time, from the Mauddud Formation reservoir of the Khabbaz Oilfield, for this reason four samples from four wells; Kz-3, Kz-4, Kz-7, and Kz-23 were selected to geochemical analysis. Analyzed geochemical parameters include TDS and the concentrations of the different dissolved cations and anions present in brines (Ca+2, Mg+2, Na+1, SO4-2, Cl-1, HCO3-1, and NaCl). Variations among the resulted data are discussed by comparison with other Cretaceous Brines. Geochemical ratios of Na/Cl, (Na-Cl)/SO4) and (Cl-Na)/Mg+2 was calculated for formation water classification following Bojarski, (1970). The calculated geochemical ratios of the studied samples in the studied four wells indicate that all of these waters are "chloride calcium" type under subsurface conditions, this type reflect closed system isolated associations reservoir, which are becoming high hydrostatic in deeper zones without influence by infiltration waters. A major transversal fault cutting the structure at its SE plunge had participated in the dilution of the Mauddud reservoir brine effectively.

Inversion-based Interpretation of Borehole Spontaneous Potential Measurements for Accurate Estimation of Water Resistivity in the Presence of Shoulder-Bed and Mud-Filtrate Invasion Effects

Electrical resistivity of formation water is a fundamental property used to quantify in situ water quality for human consumption or for assessment of hydrocarbon pore volume. Resistivity interpretation methods commonly used to quantify the electrical resistivity of formation water invoke rock porosity and fitting parameters that require additional and independent core measurements. Alternatively, the spontaneous potential (SP) log can be used to calculate water resistivity without knowledge of rock porosity in wells drilled with water-based mud. In combination with resistivity and gamma-ray logs, SP logs can be used to estimate water quality, apparent volumetric concentration of shale, and for qualitative assessments of permeability. However, SP logs often exhibit both shoulder-bed and mud-filtration effects; these effects need to be mitigated before using SP logs for calculation of water resistivity. We develop a new inversion-based method to simultaneously mitigate shoulder-bed and mud-filtrate invasion effects present in SP logs via fast numerical simulations based on Green functions. The interpretation method is implemented on SP logs acquired across aquifers with various degrees of complexity using noisy synthetic and field measurements to estimate equivalent NaCl concentration, radius of mud-filtrate invasion, and sodium macroscopic transport number. Interpretation results compare well to those obtained from resistivity and nuclear logs, provide estimates of uncertainty, and can incorporate a priori knowledge of aquifer petrophysical properties in the estimation.

The Impact of Sulfate Level Reduction on Seawater Injection Economics: Using Sulfate Scale Precipitation Kinetics to Our Advantage

ADNOC Onshore plans to use seawater as alternative to aquifer water, its source of injection water for over 40 years. However, using seawater for injection introduces a sulfate scaling risk due to incompatibility with formation water. Sulfate in the seawater and cations in the formation water (Ca, Sr) are likely to precipitate, causing scaling and related flow assurance problems and formation damage. Sulfate can be removed from the injection water by means of desulfation, but sulfate removal to well below its scaling concentration is CAPEX intensive and negatively impacts seawater flooding economics. In this paper, the economic benefits of partial sulfate reduction are evaluated, by finding a balance between controllable scaling and costs for inhibition and sulfate removal.

Water Compatibility and Scale Risk Evaluation by Integrating Scale Prediction of Fluid Modelling, Reservoir Simulation and Laboratory Coreflood Experiment for a Giant Oil Field in Offshore Abu Dhabi

An offshore field is producing oil from multiple reservoirs with peripheral water injection scheme. Seawater is injected through a subsea network and wellhead towers located along the original reservoir edge. However, because its OWC has moved upward, wells from wellhead towers are too remote to inject seawater effectively, with some portion going to the aquifer rather than oil pool. Therefore, it is planned to migrate injection strategy from peripheral to mid-dip pattern. An expected risk is scaling by mixing incompatible seawater and formation water. Such risk and mitigation measures were evaluated. To achieve the objective, the following methodology was applied: 1. Scale modelling based on water chemical analysis. 2. Define scale risk envelope with three risk categories 3. Tracer dynamic reservoir simulation to track formation water, connate water, dump flood water, injection seawater and treated seawater. 4. Review the past field scale history data 5. Coreflood experiment to observe actual phenomena inside the reservoir with various parameters such as water mixing ratio, sulphate concentration, temperature and chemical inhibitor 6. Consolidate all study results, conclude field scale risk and impact of mitigation measures. Scale prediction modelling, verified by coreflood tests, found that mixing reservoir formation water and injection seawater causes a sulphate scale risk, with risk severity depending on mixing ratio and sulphate concentration. Reservoir temperature was also found to correlate strongly with scale risk. Therefore, each reservoir should have different water management strategy. Scale impact is limited in the shallower wide reservoir with cooler reservoir temperature. Such reservoir should therefore have mid-dip pattern water injection to avoid low water injection efficiency with possible scale inhibitor squeezing as a contingency option. On the other hand, deeper reservoir has higher risk of scaling due to its higher temperature, causing scale plugging easily in reservoir pores and production wells. For such reservoir, peripheral aquifer water injection, treated low-sulphate seawater with sulphate-removal system, or no water injection development concept should be selected. By using modelling and experiment to quantify the scale risk over a range of conditions, the field operator has identified opportunities to optimize the water injection strategy. The temperature dependence of the scale risk means, in principal, that different injection strategy for each reservoir can minimize flow assurance challenges and maximize return on investment in scale mitigation measures.

Scale Mitigation for Field Implementation of Alkaline-Surfactant-Polymer ASP Flooding in a Heterogeneous High Temperature Carbonate Reservoir with High Divalent Cation Concentration in Formation Water

An alkaline-surfactant-polymer (ASP) pilot in a regular five spot well pattern is underway in the Sabriyah Mauddud (SAMA) reservoir in Kuwait. High divalent cation concentrations in formation water and high carbonate concentration of the ASP formulation makes the formation of calcite scale a concern. The main objective of this study is to investigate the severity of the calcium carbonate (CaCO3) scaling issues in the central producer in pursuit of a risk mitigation strategy to treat the potential scale deposition and reduce the flow assurance challenges. Calcite scaling risk in terms of Saturation Ratio (SR) and scale mass (in mg/L of produced water) in the pilot producer is potentially very severe and the probability of forming calcium carbonate scale at the production well is high. Produced Ca2+ concentration is high (> 800 mg/l), which makes the equilibrated calcite SR severe (> 500) and results in significant amount of scale mass precipitation. Different flooding strategies were modelled to evaluate a variety of flood design options to mitigate scale risks (varying slug size, Na2CO3 concentration, and volume of softened pre-flush brine), with marginal impact on scale formation. When the high permeability contrast of the different layers is reduced (to mimic gel injection), calcite SR and precipitated scale mass is significantly reduced to manageable levels. The option of injecting a weak acid in the production well downhole can suppress most of the expected calcite scale through reduction of the brine pH in the produced fluid stream for the ASP flood. Weak acid concentrations in the range of 4,000 to 5,000 mg/l are forecast to mitigate scale formation.

Draft Genome Sequence of Desulfovibrio sp. Strain CSMB_222, Isolated from Coal Seam Formation Water

Subsurface coal seams contain microbial consortia with various taxa, each with a different role in the degradation of coal organic matter. This study presents the sequenced and annotated genome of Desulfovibrio sp. strain CSMB_222, a bacterium isolated from eastern Australian coal seams.

An Integrated Scale Protection Package for Offshore Fractured Wells Under Designed Shut-In Extension

After fracturing, it is common practice to leave offshore wells shut-in from days to weeks for operational purposes. During the recent historic decline of demand for global crude, a trend has been witnessed to shut in even newly fractured wells under design for an extended period. The cause of these extended shut-ins can be attributed to various factors including operational logistics as well as economic factors. The shut-in extension brings some unique scaling challenges for well designs. In this paper, an integrated scale inhibitor (SI)/fracturing fluid package is presented with detailed laboratory prerequisites data to validate its efficacy for long-term scale protection during the extended shut-in. Utilizing seawater in offshore fracturing can provide significant cost savings to an operation. Unfortunately, in regions with barium-rich formations, the use of seawater brings tremendous barite scaling risk. In order to solve this challenge, the investigation focused on the selection of the most effective inhibitors for long-term barite inhibition under the simulated reservoir conditions. Along with the scale inhibitor selection, the crosslinked gel had to be carefully optimized to eliminate any potential negative interference the gel additives could impart to the performance of the inhibitor. Furthermore, the inhibitor was tested in the crosslinking system to meet optimum rheology requirements. Utilizing the broken gel containing the designed inhibitor package, barite precipitation could be prevented for months under the simulated testing conditions. Due to high levels of sulfate from seawater and the barium originating from the formation, barite scale formed immediately upon mixing of the two types of water in absence of the appropriate scale inhibitors. Solid scale products featuring slow releasing of the inhibitor ingredients was proven insufficient for this application. With extensive laboratory screening, the candidate chemistry demonstrated great brine-calcium tolerance, superior scale inhibition performance for both sulfate and carbonate scales, and the minimum interferences for the crosslinking engineering to meet necessary proppant carrying capacity. To mimic the gel-breaking process and heterogeneous bleeding from the formation water, the inhibitor was crosslinked with the gel at various loading rates (1 gpt to 10 gpt) and broken at the elevated reservoir temperature, then mixed with the different ratios of the formation water. Reliable scale inhibition performance was achieved for an extended period of time for up to six weeks. Incorporating SI into the fracturing stimulation package is a convenient method for operators to include a scale-control program into well-defined fracturing designs with minimal adjustment and also add significant cost-saving for offshore logistics and rig time (Fitzgerald, et al., 2008). The scale inhibitor product presented in this paper shows a superior solution to protect assets from scale deposition for an extended shut-in period.

Geochemical Characteristics and Origin of Formation Water From the Upper Triassic Xujiahe Tight Sandstone in the Xiaoquan-Fenggu Structural Belt, Western Sichuan Depression, China

Formation water represents an important driving force and carrier for the migration and accumulation of oil and gas; thus, research on its origin is a hot spot in petroleum geology. The Upper Triassic Xujiahe Formation in the Xiaoquan-Fenggu Structural Belt in the western Sichuan Depression, China, has developed thick tight sandstone gas reservoirs. However, previous studies have provided different conclusions on the origin of the formation water in the Xujiahe tight sandstone reservoir. In this paper, the origin of the formation water in the Xujiahe Formation was determined based on the latest major and minor elemental concentration data, hydrogen and oxygen isotopes data of formation water, and carbon and oxygen isotope data of carbonate cements. The results show that the salinity of the formation water of the Xujiahe Formation in the study area is generally greater than 50 g/L. The water type is mainly the CaCl2 type, although a small proportion of NaHCO3 type water with high salinity is observed, which is related to hydrocarbon expulsion by overpressure. Moreover, the formation water in the sandstone of the Xujiahe Formation is obviously rich in Br, which is related to membrane infiltration, overpressured hydrocarbon expulsion of shale and diagenesis of organic matter. The composition of Cl− and Na+ ions in the formation water in the Xujiahe tight sandstone reservoir is consistent with the seawater evaporation curve, which deviates significantly from the freshwater evaporation curve. The hydrogen and oxygen isotopes of condensate water in the Xujiahe Formation tight sandstone are similar to those of atmospheric precipitation water, while the hydrogen and oxygen isotopes of the formation water in the Xujiahe Formation show that it is of seawater origin. Therefore, to use hydrogen and oxygen isotopes to determine the origin of formation water, condensate water must be accurately differentiated from formation water. Otherwise, if the condensate water is misjudged as formation water, then incorrect conclusions will be drawn, e.g., that the formation water of the Xujiahe Formation originated from fresh water. Affected by organic carbon, the carbon isotope Z value of the carbonate cements in the Xujiahe Formation is low (mainly distributed between 110 and 130). A Z value of less than 120 does not indicate that the ancient water bodies formed by cements were fresh water or mixed water bodies. However, Z values greater than 120 correspond to a formation temperature lower than 80 C, which indicates that carbonate cement was not affected by organic carbon; thus, the Z value can reflect the origin of ancient water bodies. The results of this study indicate that the formation water of the Xujiahe tight sandstone in the study area is of seawater origin. The determination of the origin of the formation water and seawater of the Xujiahe Formation provides strong evidence for the determination of the marine sedimentary environment of the Xujiahe Formation in the study area, and can provide scientific guidance for the search for high-quality reservoirs.