Salaheldin Elkatatny

New insights into the prediction of heterogeneous carbonate reservoir permeability from well logs using artificial intelligence network

Permeability is an important parameter for oil and gas reservoir characterization. Permeability can be traditionally determined by well testing and core analysis. These conventional methods are very expensive and time-consuming. Permeability estimation in heterogeneous carbonate reservoirs is a challenge task to be handled accurately. Many researches tried to relate permeability and reservoir properties using complex mathematical equations which resulted in inaccurate estimation of the formation permeability values. Permeability prediction based on well logs using artificial intelligent techniques was presented by many authors. They used several wire-line logs such as gamma ray, neutron porosity, bulk density, resistivity, sonic, spontaneous potential, hole size, depths, and other logs. The objective of this paper is to develop an artificial neural network (ANN) model that can be used to predict the permeability of heterogeneous reservoir based on three logs only, namely resistivity, bulk density, and neutron porosity. In addition to the ANN model, in this paper and for the first time a mathematical equation from the ANN model will be extracted that can be used for permeability prediction for any data set without the need for the ANN model. Also, in this study and for the first time we introduced a new term which is the mobility index that can be used effectively in the permeability prediction. Mobility index term is derived from the mobile oil saturation that occurred due to the drilling fluid filtrate invasion. The obtained results showed that ANN model gave a comparable results with support vector machine and adaptive neuro-fuzzy inference system model. The developed mathematical equation from ANN model can be used to estimate the permeability for heterogamous carbonate reservoir based only on three parameters: bulk density, neutron porosity, and mobility index. Actual core data points (1223 points) with the three logs were used to train (857 data points, 70% of the data) and test the model for unseen data (366 data points, 30% of the data). The correlation coefficient for training and testing was 0.95, and the root-mean-square error was 0.28. The developed mathematical equation will help the engineers to save time and predict the permeability with a high accuracy using inexpensive technique. Introducing the new parameter, mobility index, in the prediction process greatly improved the permeability prediction from the log data compared to the actual measured data.

Development of a new correlation to determine the static Young’s modulus

The estimation of the in situ stresses is very crucial in oil and gas industry applications. Prior knowledge of the in situ stresses is essential in the design of hydraulic fracturing operations in conventional and unconventional reservoirs. The fracture propagation and fracture mapping are strong functions of the values and directions of the in situ stresses. Other applications such as drilling require the knowledge of the in situ stresses to avoid the wellbore instability problems. The estimation of the in situ stresses requires the knowledge of the Static Young’s modulus of the rock. Young’s modulus can be determined using expensive techniques by measuring the Young’s modulus on actual cores in the laboratory. The laboratory values are then used to correlate the dynamic values derived from the logs. Several correlations were introduced in the literature, but those correlations were very specific and when applied to different cases they gave very high errors and were limited to relating the dynamic Young’ modulus with the log data. The objective of this paper is to develop an accurate and robust correlation for static Young’s modulus to be estimated directly from log data without the need for core measurements. Multiple regression analysis was performed on actual core and log data using 600 data points to develop the new correlations. The static Young’s modulus was found to be a strong function on three log parameters, namely compressional transit time, shear transit time, and bulk density. The new correlation was tested for different cases with different lithology such as calcite, dolomite, and sandstone. It gave good match to the measured data in the laboratory which indicates the accuracy and robustness of this correlation. In addition, it outperformed all correlations from the literature in predicting the static Young’s modulus. It will also help in saving time as well as cost because only the available log data are used in the prediction.

Removal of water-based filter cake and stimulation of the formation in one-step using an environmentally friendly chelating agent

Chelate solutions, GLDA (pH of 3.3 to 13) and HEDTA (pH of 4 and 7) were incompatible with α-amylase over a wide range of temperatures. GLDA (pH 3.3) and HEDTA (pH 4) can be used to remove the filter cake in one step. GLDA (20 wt% in a 200 g solution and pH of 3.3) and HEDTA (20 wt% in a 200 g solution and pH 4) had 100% removal efficiency of the filter cake. The retained permeability was 110% and 106% for Berea sandstone and Indiana limestone cores, respectively when using GLDA (13.3 wt% in 300 g solution and pH of 3.3). The retained permeability was 115% and 100% for Berea sandstone and Indiana limestone cores, respectively when using HEDTA (20 wt% in 200 g solution and pH of 3.3). No core damage was observed when using GLDA and HEDTA solutions as a breaker to remove water-based filter cake.

Properties of Ilmenite Water-Based Drilling Fluids for HPHT Applications

Barite is the most common weighting material for drilling fluids, which contain several heavy components including lead, cadmium, mercury, and arsenic. Some of these heavy materials can discharge into the sea, which is not allowed especially in the case of oil-based drilling fluid. The supply of barite is geographically limited, with high transportation costs. To overcome the high cost, shortage, and common problems of barite, an alternative weighting material, ilmenite (5 μm), is introduced which is heavier than barite and more stable at high temperature. Also, the micronized ilmenite was introduced to overcome the ECD challenges in some drilling operations at reasonable cost. Extensive lab work was done in order to: 1) optimize the rheological properties of the drilling fluid, 2) determine the optimum pH that gives stable dispersion, 3) assess the thermal stability, 4) optimize the filtration parameters (filtrate volume and filter cake thickness), and 5) characterize the ilmenite-based filter cake. Zeta potential results showed that ilmenite was stable when mixed with water at a pH above 7 and it was dispersed and stable when mixed with the drilling fluid components. Drilling fluids have a density range from 100 to 120 pcf and a plastic viscosity of 28-32 cp. The optimized water-based drilling fluid formula had a small filtrate volume (12 cm3) and thin filter cake (0.2 in.) under dynamic conditions. SEM analysis showed that ilmenite filter cake was heterogeneous and contained ilmenite particles in the layer closer to the rock surface. The kem-seal plus had a big effect to control the rheological properties of the drilling fluid at 350˚F. This study will provide a complete evaluation of the drilling fluids with ilmenite as a weighting material and will help drilling engineers to better design drilling fluids for HPHT wells.

Removal Efficiency of Water-Based Drill-In Fluid Filter Cake Using Polylactic Acid

Water-based drilling fluids consist of xanthan gum, starch, sized calcium carbonate and salt particles to increase mud density was used to drill horizontal wells. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, and chelating agents are limited at certain conditions. A drilling fluid was designed based on calcium carbonate particles and an ester of lactic acid. The objective of the latter is to remove calcium carbonate once the drilling operation is complete and there is a need to remove the filter cake. Extensive lab work was done to; 1) determine thermal stability of the drilling fluid (70-72 pcf) for 24 hrs, 2) characterize the filter cake using a computer tomography, 3) assess potential formation damage for different rock types (limestone and sandstone) using a modified HPHT filter press, and 4) determine the removal efficiency of the filter cake and the return permeability. The results obtained showed that the drilling fluid has stable rheological properties up to 300oF over 24 hrs. CT scan showed that the filter cake contained two layers, one layer closed to the rock surface, which contained a mixture of calcium carbonate and acid-precursor and one layer closed to the drilling fluid that contained a mixture of XC-polymer and starch. The polymer layer was removed by using 10% solution of alpha amylase. The rest of the filter cake was removed by lactic acid that was produced from the hydrolysis of the ester. The removal efficiency of the filter cake was nearly 80% and the return permeability was about 100%. The decrease in CT number of the core after the removal process indicated that the filter cake was completely removed. This paper will discuss the development of this new drilling fluid and will give recommendations for field applications.

An integrated approach for estimating static Young’s modulus using artificial intelligence tools

Elastic parameters play a key role in managing the drilling and production operations. Determination of the elastic parameters is very important to avoid the hazards associated with the drilling operations, well placement, wellbore instability, completion design and also to maximize the reservoir productivity. A continuous core sample is required to be able to obtain a complete profile of the elastic parameters through the required formation. This operation is time-consuming and extremely expensive. The scope of this paper is to build an advanced and accurate model to predict the static Young’s modulus using artificial intelligence techniques based on the wireline logs (bulk density, compressional time, and shear time). More than 600 measured core data points from different fields were used to build the AI models. The obtained results showed that ANN is the best AI technique for estimating the static Young’s modulus with high accuracy [R2 was 0.92 and the average absolute percentage error (AAPE) was 5.3%] as compared with ANFIS and SVM. For the first time, an empirical correlation based on the weights and biases of the optimized ANN model was developed to determine the static Young’s modulus. The developed correlation outperformed the published correlations for static Young’s modulus prediction. The developed correlation enhanced the accuracy of predicting the static Young’s modulus. (R2 was 0.96 and AAPE was 6.2%.) The developed empirical correlation can help geomechanical engineers determine the static Young’s modulus where laboratory core samples are not available.

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

The oil reservoir pressure declines due to oil production, and this decline will lead to reduction in the oil productivity. The reservoir pressure maintenance is a practice in the oil industry in which seawater is injected into the aquifer zone below the oil zone to support the reservoir pressure. Calcium sulfate scale is one of the most serious oilfield problems that could be formed in sandstone and carbonate reservoirs. Calcium sulfate may precipitate during the injection of seawater with high sulfate content into formation brine with high calcium content. Mixing seawater and formation water may cause precipitation of calcium sulfate, barium sulfate, and/or strontium sulfate. Seawater treatment does not remove the entire sulfate ions from the injected water. Low sulfate concentrations may cause damage. Enhanced oil recovery processes such as smart water injection, which originally is diluted seawater, may cause calcium sulfate precipitation as the reduction of water salinity will increase the sulfate precipitation and decrease its solubility. This study was conducted to investigate the damage caused by the deposition of calcium sulfate precipitation. A solution is proposed to prevent the damage due to calcium sulfate by using chelating agents. Several coreflooding experiments were conducted using Berea sandstone and Indiana limestone cores at reservoir conditions of pressure and temperature using seawater (high and low salinity) and formation water. Chelating agents used in this study are: EDTA (ethylenediaminetetraacetic acid), HEDTA (hydroxyethylenediaminetriacetic acid), and HEIDA (hydroxyethyliminodiacetic acid). HEDTA and HEIDA chelating gents are environmentally friendly and can be used in marine environment. High-salinity water injection caused severe formation damage, and the injectivity will decline faster compared to the low-salinity water injection. HEDTA and EDTA chelating agents at low concentrations performed better than HEIDA chelating agents in both Berea sandstone and Indiana limestone cores. HEDTA and EDTA chelating agents were able to prevent the damage due to calcium sulfate precipitation and enhanced the core permeability.

Flow Rate-Dependent Skin in Water Disposal Injection Well

Reinjection is one of the most important methods to dispose fluid associated with oil and natural gas production. Disposed fluids include produced water, hydraulic fracture flow back fluids, and drilling mud fluids. Several formation damage mechanisms are associated with the injection including damage due to filter cake formed at the formation face, bacteria activity, fluid incompatibility, free gas content, and clay activation. Fractured injection is typically preferred over matrix injection because a hydraulic fracture will enhance the well injectivity and extend the well life. In a given formation, the fracture dimensions change with different injection flow rates due to the change in injection pressures. Also, for a given flow rate, the skin factor varies with time due to the fracture propagation. In this study, well test and injection history data of a class II disposal well in south Texas were used to develop an equation that correlates the skin factor to the injection flow rate and injection time. The results show that the skin factor decreases with time logarithmically as the fracture propagates. At higher injection flow rates, the skin factor achieved is lower due to the larger fracture dimensions that are developed at higher injection flow rates. The equations developed in this study can be applied for any water injector after calibrating the required coefficients using injection step rate test (SRT) data.

New approach to evaluate the equivalent circulating density (ECD) using artificial intelligence techniques

The equivalent circulation density (ECD) is a very important parameter in drilling high-pressure high-temperature and deepwater wells. ECD is a key parameter during drilling through formations where the margin between the pore pressure and the fracture pressure (FP) is narrow. In these critical formations, the ECD is used to control the formation pressure and prevent kicks. Recent approaches in oilfields to determine ECD depend mainly on using expensive downhole sensors for providing real-time values of ECD. Most of these tools have operational limitations such as high pressure and high temperature which may prevent using these tools in downhole conditions. The objective of this paper is to develop a new approach for predicting ECD using artificial intelligence (AI) techniques from surface drilling parameters [mud weight, drill pipe pressure, and rate of penetration (ROP)]. 2376 data points were used to develop the AI models. The data were collected during the drilling of an 8.5″ vertical hole section. Two AI models were used to estimate the ECD: artificial neural network (ANN) and adaptive neuro-fuzzy inference system (ANFIS). An empirical correlation for ECD was derived from the optimized ANN model by extracting the weights and biases. The developed ANN and ANFIS models were able to calculate ECD with a correlation coefficient (R) of 0.99 and average absolute percentage error of 0.22% for ANN and ANFIS models, respectively. The developed empirical correlation for the ANN model can be used during well design to choose a correct mud weight to safely drill the well based on the expected drilling parameters. It will also minimize the drilling problems related to ECD such as losses or gains especially in critical situations where the margin between the pore and fracture pressure is very narrow. In addition, using this technique will save cost and time by reducing the need for expensive, complicated downhole tools.

Efficiency of Removing Filter Cake of Water-Based Drill-in Fluid Using Chelating Agents Utilizing a CT Method

Hydrochloric acid, organic acid, or a mixture of these acids is used to remove filter cake, which consists mainly of calcium carbonate. However, the use of these acids in horizontal and deep wells has some major disadvantages, including high and uncontrolled reaction rate and corrosion to well tubular. To overcome these problems, chelating agents are used in oil and gas wells. Extensive lab studies were done to determine: 1) the compatibility of various chelates with α-amylase at different pH values, 2) the optimum pH that should be used to remove filter cake, 3) the efficiency of filter cake removal using a modified HPHT filter press, 4) the return permeability of sandstone and limestone cores, and 5) assess the potential of formation damage using a computer tomography scanner. All of these tests were conducted at temperatures up to 225°F. The results obtained showed that chelate solutions, GLDA (pH of 3.3 13) and HEDTA (pH 4 and 7) were incompatible with α-amylase solutions over a wide range of temperatures. At high pH, various chelates had removal efficiency of 40% and retained permeability of 30%, which indicated formation damage. To solve this problem, 20 wt% of the chelating agents at low pH (3.3 4) were used to remove the filter cake without the enzyme stage. The results obtained showed that the retained permeability increased to 85% for limestone cores and 110% for sandstone cores. The removal efficiency of the filter cake was 100% for limestone and sandstone cores. CT results showed that no formation damage was observed when using chelating agents as a breaker to remove the filter cake. Introduction The objective of horizontal and multilateral wells is to improve the well productivity by maximizing reservoir contact and enhance the hydrocarbon recovery, Yildiz (2005). Leakoff of drilling fluids into the formation can cause severe damage. To minimize this damage, the drilling fluid should be able to form a fast, impermeable, and low thickness filter cake on the wall of the formation. To increase the reservoir productivity, it is important to remove not only the filter cake from the surface of the formation, but also the low permeability invaded zone, which was formed during drilling operations. Traditional methods that were used to remove calcium carbonate filter cake included the use of live acids, organic acids (Ali et al. 2000), oxidizing agents (Bardy et al. 2000), chelating agents (Parlar et al. 1999), enzymes (Al-Otabi and Nasr-ElDin 2005), in-situ organic acids (Nasr-El-Din et al. 2005), or a combination of these chemicals (Hembling et al. 2000). Price-Smith et al. (2003) mentioned that uniform filter cake removal cannot be achieved by using acids which have rapid reaction. Parlar et al. (1999) concluded that it is not recommended to use acids in long horizontal wells, due to large volume of acid that is required to remove the filter cake. Burnet et al. (1994) mentioned that polymers may coat calcium carbonate particles and act as a barrier which minimizes acid contact with the filter cake. Hodge et al. (1996) stated that oxidizers were not effective in removing polymer damage, especially in horizontal wells. Brannon and Tjon (1994) concluded that acids and oxidizers attacked any active sites on polymer strands, but they did not react with the polymer backbone and they left partially degraded and unreacted polymer strands. Humbling et al. (2000) stated that enzymes cannot remove the filter cake completely; but it was effective in removing polymer material in filter cake. Todd (2001) mentioned that oxidizing agents or enzymes did not dissolve calcium carbonate particles. Al-Otaibi et al. (2004) mentioned that enzymes were able to break XC-polymers and starches that were used in drillin fluid. Nasr-El-Din et al. (2005) studied the effect of using in-situ generated acid, which generated acetic acid, to remove filter cake. They concluded that this system can remove most of the acid-soluble material only. They recommended using this