Construction of Comprehensive Geological Model for an Iraqi Oil Reservoir

The paper generates a geological model of a giant Middle East oil reservoir, the model constructed based on the field data of 161 wells. The main aim of the paper was to recognize the value of the reservoir to investigate the feasibility of working on the reservoir modeling prior to the final decision of the investment for further development of this oilfield. Well log, deviation survey, 2D/3D interpreted seismic structural maps, facies, and core test were utilized to construct the developed geological model based on comprehensive interpretation and correlation processes using the PETREL platform. The geological model mainly aims to estimate stock-tank oil initially in place of the reservoir. In addition, three scenarios were applied based on sensitivity and uncertainty of five variables to determine an accurate estimation of stock-tank oil initially in place of the reservoir. The oil-water contact appeared to be the major uncertain parameter for stock-tank oil initially in place estimation because the available geological and field data was not enough to demonstrate it confidently, and only 13% of the total wells have penetrated the water zone in the Mishrif formation. The results of all scenarios indicate that the reservoir has huge stock-tank oil initially in place. The importance of developing this oilfield is validated by its very high stock-tank oil. This is where the value of this study becomes obvious.

Accuracy and Precision of Reservoir Fluid Characterization Tests Through Blind Round-Robin Testing

Objectives/Scope: Oil and gas operators use a variety of reservoir engineering workflows in addition to the reservoir, production, and surface facility simulation tools to quantify reserves and complete field development planning activities. Reservoir fluid property data and models are fundamental input to all these workflows. Thus, it is important to understand the propagation of uncertainty in these various workflows arising from laboratory fluid property measured data and corresponding model uncertainty. The first step in understanding the impact of laboratory data uncertainty was to measure it, and as result, ADNOC Onshore undertook a detailed study to assess the performance of four selected reservoir fluid laboratories. The selected laboratories were evaluated using a blind round-robin study on stock tank liquid density and molar mass measurements, reservoir fluid flashed gas and flashed liquid C30+ reservoir composition gas chromatography measurements, and Constant Mass Expansion (CME) Pressure-Volume-Temperature (PVT) measurements using a variety of selected reservoir and pure components test fluids. Upon completion of the analytical study and establishing a range of measurement uncertainty, a sensitivity analysis study was completed using an equation of state (EoS) model to study the impact of reservoir fluid composition and molecular weight measurement uncertainty on EoS model predictions. Methods, Procedures, Process: A blind round test was designed and administered to assess the performance of the four laboratories. Strict confidentiality was maintained to conceal the identity of samples through blind test protocols. The round-robin tests were also witnessed by the researchers. The EoS sensitivity study was completed using the Peng Robinson EoS and a commercially available software package. Results, Observations, Conclusions: The results of the fully blind reservoir fluid laboratory tests along with the statistical analysis of uncertainties will be presented in this paper. One of the laboratories had a systemic deviation in the measured plus fraction composition on black oil reference standard samples. The plus fraction concentration is typically the largest weight percent component in black oil systems and, along with the plus fraction molar mass, plays a crucial role in establishing the mole percent overall reservoir fluid compositions. Another laboratory had systemic issues related to chromatogram component integration errors that resulted in inconsistent carbon number concentration trends for various components. All laboratories failed to produce consistent molecular weight measurements for the reference samples. Finally, one laboratory had a relative deviation for P-V measurements that were significantly outside the acceptable range. The EoS sensitivity study demonstrates that the fluid composition and stock tank oil molar mass measurements have a significant impact on EoS model predictions and hence the reservoir/production models input when all other parameters are fixed. Novel/Additive Information: To the best of our knowledge, this is the first time such an extensive and fully blind round-robin test of commercial reservoir fluid characterization laboratories has been completed and published in the open literature. The industry should greatly benefit from this first-of-its-kind blind round-robin dataset being made available to all. The study provides the basis, protocols, expectations, and recommendations for such independent round-robin testing for fluid characterization laboratories on a broader scale.

Intelligent Well Drainage and Interference Density Analysis Tool for Optimizing Infill Drilling

During the progressive development of mature fields, it is imperative to drill many infill wells to accelerate production and access bypassed oil. Optimizing the infill well spacing is always the concern to reduce interference with existing wells and improve recovery. In the present study, using intelligent data mining techniques, a new analysis and visualization tool has been developed and implemented to estimate and map drainage radius by well to assess the efficiency of the current development pattern and properly plan future wells. The tool deployed several performance-based techniques to estimate the contacted stock-tank oil initially in place (STOIIP) by each existing well, and outcomes can be compared between techniques for validation. The contacted STOIIP is then converted into an effective drainage radius by well using reservoir properties from the geo-cellular model. The evaluated reservoir is subdivided vertically into pay zones drained by the wells based on geological barriers/baffles to flow and connectivity across the zones. The tool estimates drainage radii of the wells produced from the reservoir using five different methods. The resultant Proved Developed Producing (PDP) reserves polygon maps are generated for the connected zones. The drainage radii of wells with behind-casing opportunities are estimated based on correlation and adjacent wells methods, and Proved Developed Non-Producing (PDNP) reserves polygon maps were generated. Well interference density is estimated based on overlapping drainage radii polygons with adjacent well locations, which has then been validated with production and pressure data from the wells. This paper describes the methodology by which the well drainage radii and well interference density can be estimated and implemented on a selected reservoir. This workflow can be successfully used to identify drained and undrained areas around the wellbore and opportunities for additional infill wells in the various pay zones of the reservoir. This exercise observed consistency in the drainage radii cumulative distribution from decline curve analysis methods and the No-Further-Activities (NFA) simulation case.

The Evolution of CaCO3 Scaling Potential in ADNOC Reservoirs Under Water Flooding and CO2 WAG Scenarios

Wells producing from an oilfield in Abu Dhabi were investigated to understand the CaCO3 scaling risk at current production conditions, and to predict how the downhole and topside scaling potential will change during a planned CO2 WAG project. The results of this study will be used to design the correct scale inhibitor treatment for each production phase. A rigorous scale prediction procedure for pH dependent scales previously published by the authors was applied using a commercial integrated PVT and aqueous modelling software package to produce scale prediction profiles through the system. This procedure was applied to run many sensitivity studies and determine the impact of field data variables on the final scale predictions. These results were used to examine the scaling potential of current and future fluids by creating a diagnostic "what if" chart. Some of the main variables investigated include changes in operating pressure, CO2 and H2S concentrations and variable water cut. Scale prediction profiles through the entire system from reservoir to stock tank conditions were obtained using the above modelling procedure. The main findings in this study are: (i) That CaCO3 scale is not predicted to form at separator conditions under any of the current or future scenarios investigated for these wells. This is due to the high separator pressure which holds enough CO2 in solution to keep the pH low and prevent scale precipitation. (ii) The water at stock tank conditions was found to be the critical point in the system where the CaCO3 scaling risk is severe, and where preventative action must be taken. (iii) Implementing CO2 WAG does not affect CaCO3 scaling risk at separator conditions where fluids remain undersaturated. However, the additional CO2 dissolves more CaCO3 rock in the reservoir producing higher alkalinity fluids which result in more CaCO3 scale precipitation at stock tank conditions. (iv) Fluids entering the wellbore are likely to precipitate some CaCO3 (albeit at a fairly low saturation ratio, SR) due to a significant pressure drop and the relatively high temperature, and this is not associated with the-bubble point in this case. This downhole scaling potential becomes slightly worse by an increase in CO2 concentration during CO2 WAG operations.(v) Scale inhibitor may or may not be required to treat downhole fluids depending on the wellbore pressure drop, but it is always necessary to treat fluids downstream of the separator due to the very high scaling potential at stock tank conditions. By applying a rigorous scale prediction procedure, it was possible to study the impact of CO2 WAG on the risk of CaCO3 scale precipitation downhole and topside for this field. These results highlight the current threat downhole and at stock tank conditions in particular and show how this will worsen with the implementation of CO2 WAG and this will require a chemical treatment review.

PSI-11 Effects of a supplemental water source and trace-mineral based electrolyte drinking solution on intake and blood cell count of newly received feedlot calves

Oral hydration therapy has been used to improve performance and health of newly received feedlot calves; however, little is known regarding water intake (WI) following arrival at the feedlot. Our objective was to evaluate WI of newly received feedlot calves provided a supplemental water source or a novel nutritional rehydration solution during initial 3 days following arrival. Crossbred heifers (n=180; initial BW = 237 ± 23 kg) were individually weighed after 16 h fasting and sorted into 12 pens (4 pens/treatment). Treatments were: 1) Control (CON): water provided through standard in-pen automatic waterer only (Richie CM480; one waterer/pen); 2) Supplemental water (SUPW): CON + water provided with one additional stock tank/pen; 3) Novel nutritional rehydration solution (NRS): trace-mineral based drinking solution provided with one stock tank/pen as the only water source. Treatments were provided from days 0 to 3 after which supplemental tanks were removed. From days 4 to 14 all heifers had access to the standard in-pen automatic waterer only. The WI was measured daily throughout the trial and BW was recorded at days 0 and 14. Whole blood was collected (5 heifers/pen) on days 0, 3, and 14. Treatments had no effect on DMI or ADG (P ≥ 0.15). SUPW and NRS had greater WI than CON from days 0 to d 3 (P ≤ 0.001), but not from days 4 to 14 nor from days 0 to 14 (P = 0.69). No treatment effect or treatment × day interactions were observed for total red (RBC) or white blood cell counts (WBC; P ≥ 0.19); however, a day effect was present (P < 0.001) and RBC and WBC linearly decreased from day 0 to 14 (P < 0.05). Our preliminary results indicate that providing a supplemental source of water during the initial 3 d after arrival increased total WI and may facilitate rehydration in stressed calves following transit.

Application of Air Cooled Heat Exchangers for Condensation of Natural Gas Liquids from Associated Petroleum Gas

The paper describes a method for increasing a yield of stock-tank oil by reducing liquid carryover with associated petroleum gas at crude processing facilities (CPF) of one oil field in Iraq by cooling the feed stream in air cooled heat exchangers. An integrated model of the field has been built consisting of: models of well tubings, models of wellhead chokes, an integrated model of oil gathering network, a model of air cooled heat exchangers, a model of material and heat balance of CPF. The air cooler performance in oil treatment has been asessed in accordance with ambient temperature profile. The main advantages and disadvantages of using the proposed scheme are shown in the article. Considered in the article the air cooler has been originally designed and manufactured for use in another field. Therefore, one of the tasks was to validate the applicability of that air cooler unit in the oil treatment process for a field with facilities in-place. The novelty of the study lies in the non-standard use of an air cooled heat exchangers in the oil treatment. The results of simulation of using air cooling units in oil treatment and the actual operation of air coolers showed increased output of crude oil at the CPF at low capital and operating costs.

Optimized Completions Design Using Retrofit Autonomous Inflow Control Devices

Discovered in 1964, the Beta Field in the Niger Delta sedimentary basin consists of 25 stacked hydrocarbon-bearing reservoirs located between 5,500 and 12,000 feet true vertical depth subsea (TVDSS). A total of 26 wells have been drilled in the field, of which 11 are presently on production. Oil production peaked at 8,900 stock-tank barrels per day shortly after field start-up and has been on the decline. More than 40 years since production start-up, the Beta Field remains a relatively immature, distinctly underdeveloped asset. Only about 59 million stock tank barrel (STB), or 8% of its estimated stock-tank oil initially in place of 740 million STB, had been produced by the end of 2017. Two horizontal wells were planned in the field to provide additional drainage points and increase field production. However, a production forecast of the planned wells showed potential early water breakthrough and high water cut because of unfavorable mobility ratios of a slightly viscous oil and proximity to oil/water contact (OWC). To mitigate the production challenges and improve the reservoir sweep, autonomous inflow control devices (AICDs) were selected to be installed on the sandface completion. These wells were drilled and completed during the COVID-19 pandemic, bringing additional challenges in equipment availability and logistics with potential to derail the successful completion of these wells within the required timeline. An innovative retrofit screen design, leveraging detailed engineering design and remote collaboration, enabled the conversion of ICD sand control screens to cyclonic AICD screens. AICD nozzle placement was optimized using a reservoir-centric workflow that integrates the full reservoir model with the sandface completion. Real-time interpretation of the data enabled computation of porosity-permeability and saturation estimates from logging-while-drilling (LWD) logs, which was then used in updating the reservoir model in near-real time. Using a segmented well modeling approach and a refined flow distribution from heel to toe, AICD nozzle placement was optimized in real time utilizing LWD measurements from open hole along the horizontal drain, aiding the design and configuration of the AICDs. The Beta-7 and Beta-8 wells were successfully drilled, completed, and put on production. The horizontal drains were landed within 5 to 10 feet of the top of the reservoir, maintaining at least 20-ft distance from the OWC. The forecasted simulation showed possible water influx from the toe of the horizontal as opposed to the heel because of existing water leg and high permeability at the toe. This was supported by high water-cut production from that zone in the nearby wells. This insight from the full-field simulation model enabled an informed decision on the AICD design.

OPTIMIZING OIL PRODUCTION AT THE GATHERING STATION BY MAINTAINING THE OIL STOCK TANK / INTERFACE LEVEL IN THE WASH TANK USING THE ROC SYSTEM

One of the production problems that arise at the Gathering Station is an unstable production problem, this is caused by controlling the level of fluid in the wash tank that is less than the maximum for that need to be improved by changing the system from manual to automatic. To maintain the stability of production at the gathering station, special measures such as controlling fluid levels in the storage tanks need to be carried out, monitoring pressure, temperature monitoring and so on that can have a positive effect on oil production at the gathering station. Wash Tank is a tank that is useful for temporary storage of liquid fluid (liquid) that comes from the boot gas. The liquid fluid entering the wash tank consists of a mixture of crude oil and water. At the Wash tank the process of separation between crude oil and water. This washing tank is the largest tank compared to other processing tanks at the gathering station, its diameter is around 85 ft to 90 ft, and its height is around 35 ft to 40 ft. The normal level in the separation process is 36 ft, where the level 1 ft - 29 ft is the water level, while the level 29 ft - 36 ft is the oil level. The 1ft - 29 ft level is referred to as the interface level, where the water level is expected to be at level 29 and the thickness of the oil / oil stock tank 7 ft in the wash tank. Research conducted on the problem of controlling the level of fluid in the wash tank, where manual control is ineffective and inefficient, for this reason it is necessary to change from a manual to automatic process with the ROC (Remote Operation Control) system, the changes made are expected to maintain the interface and the oil stock tank in accordance with the set point that has been determined and where the amount of oil production per day at the gathering station is very influential on the oil stock tank so that the oil pumped to the shipping line has a BS&W below 1% and has a temperature of 130 ° F -150 ° F In order to obtain this value, we must maintain the interface and the oil stock tank in accordance with the specified set point and where the amount of oil production per day at the gathering station is very influential on the oil stock tank

Method Quantifies Separator-Oil Shrinkage

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19775, “Quantifying Separator-Oil Shrinkage,” by Mathias Lia Carlsen, SPE, and Curtis Hays Whitson, SPE, Whitson, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. In tight unconventionals, oil and gas rates often are measured daily at separator conditions. Consequently, converting these rates reliably to volumes at standard conditions is necessary in cases where direct stock-tank measurements are not available. Because of changes in producing-wellstream compositions and separator conditions, the separator-oil shrinkage factor (SF) can change significantly over time. The complete paper presents a rigorous and consistent method to convert daily separator rates into stock-tank volumes. Recommendations for developing field-specific shrinkage correlations using field test data also are proposed. SF and Flash Factor (FF) Separator-Oil SF. Separator-oil SF is the fraction of metered separator oil rate that remains (or transforms into) stock-tank oil after further processing to standard conditions of 1 atm and 60°F. Put simply, the SF quantifies the decrease in oil volume from separator conditions to stock tank. The magnitude can range from less than 0.65 to 0.99. Separator-Oil FF. Separator-oil FF is the ratio of liberated gas from metered separator oil after further processing to standard conditions of 1 atm and 60°F. The FF accounts for the increase in gas volume from separator conditions to stock tank and explains why oil is shrinking (i.e., gas is coming out of the solution). The magnitude of the FF can range from 5 to 1,000 scf/STB. Total producing gas/oil ratio (GOR) can be calculated easily when SF and FF are known. An SF always is associated with an FF and is literally the solution GOR of the separator oil. Both SF and FF are a function of the top-side surface process and an associated wellstream composition. Surface Process. The surface process represents the number of topside separation stages and the associated separator pressure and temperature of each stage. In shale basins, two- and three-stage separation trains are common. The number of separation stages typically is fixed throughout the lifetime of a well. However, the separator temperature and pressure may vary significantly. Wellstream Composition. The well-stream composition quantifies the relative amounts of different components flowing out of a well at a given day. This measurement is typically expressed in mol%. Tight unconventional basins contain many kinds of in-situ reservoir fluid compositions from dry gas to black oils. The produced-wellstream compositions from these systems tend to change considerably with time because of producing flowing bottomhole pressures below the saturation pressure, as seen in the field example presented in Fig. 1. In the figure, the shut-in period after approximately 330 days results in a transient period with large compositional changes.