A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the US and Bahrain field in Bahrain). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance. This page discusses gas injection into oil reservoirs to increase oil recovery by immiscible displacement.
Baruah, Nabajit (Oil & Natural Gas Corporation) | Mandal, Dipak (Oil & Natural Gas Corporation) | Jena, Smita Swarupa (Oil & Natural Gas Corporation) | Sahu, Sunil Kumar (Oil & Natural Gas Corporation)
This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.
For mature oil fields with complicated reservoir architecture, reservoir surveillance is key to track reservoir performance. Reservoir surveillance may include various monitoring tools from complicated horizontal production logging tools down to regular well tests. One of the main surveillance methods is running formation pressure measurement tools such as Formation Pressure Testers (FPT) or as historically known to the industry, Repeated Formation Tester (RFT). This paper describes the use of this important tool integrated with production data to understand reservoir production and depletion behavior and hence support the Bahrain Field development plan.
A study was conducted on the Ostracod and Magwa reservoirs; complicated carbonate reservoirs in the Bahrain Field. The Ostracod Zone is a sequence of inter-bedded limestone and shale in the upper Rumaila formation of the middle Cretaceous Wasia group. It is over 200 feet thick and consists of three main units: B0, B1, and B2. The Magwa reservoir is the lower member of the Rumaila Formation. It is 120 feet thick and conformably underlies the Ostracod reservoir. It consists of three main units: M1, M2, and M3.
The main objectives of this study are:
Evaluating pressure depletion from the initial reservoir pressure for each unit in both reservoirs, which defined the existence of flow barriers in this inter-bedded complicated carbonate. Evaluating the relationship between pressure depletion in each unit and the spacing between offset wells to the FPT location. Evaluating the Ostracod/Magwa pressure depletion per unit with time. Linking the pressure depletion to the cumulative production from the area offset by the FPT data.
Evaluating pressure depletion from the initial reservoir pressure for each unit in both reservoirs, which defined the existence of flow barriers in this inter-bedded complicated carbonate.
Evaluating the relationship between pressure depletion in each unit and the spacing between offset wells to the FPT location.
Evaluating the Ostracod/Magwa pressure depletion per unit with time.
Linking the pressure depletion to the cumulative production from the area offset by the FPT data.
The results of this study helped define the depletion risk on the future infill opportunities in such complicated reservoirs. It also helped in locating highly depleted units and determining the optimal locations for the new infill wells.
The Light Oil Steam Flood (LOSF) is proposed to increase the recovery from Mauddud reservoir in Bahrain Field. Mauddud has been on gas injection since 1938, yet residual oil saturation is still high in the gas cap due to its oil wettability. Several core lab studies were conducted confirming the high oil saturation in the gas cap. Steam flood core lab experiments were conducted recently and confirmed the residual oil saturation could reach to less than 10%. The thermal pilot project in Mauddud has gone through the following stages: The first pilot started in 2013 and operated for 2.5 years: It has one horizontal well in the gas cap, one vertical producer, four vertical injectors with three Temperature Observation Wells (TOWs) clustered around one of the injectors. First pilot performance was assessed and confirmed in reducing the residual oil in the gas cap by distillation and wettability alteration. Second pilot was designed and initiated in 2016 to assess the economic viability for full field expansion.
The first pilot started in 2013 and operated for 2.5 years: It has one horizontal well in the gas cap, one vertical producer, four vertical injectors with three Temperature Observation Wells (TOWs) clustered around one of the injectors.
First pilot performance was assessed and confirmed in reducing the residual oil in the gas cap by distillation and wettability alteration.
Second pilot was designed and initiated in 2016 to assess the economic viability for full field expansion.
Throughout these stages, production monitoring, logging, core studies and simulation studies have been carried to understand the LOSF mechanisms to increase Mauddud recovery from the gas cap.
This paper presents the evolution of pilot design concepts and simulation of the thermal recovery in Mauddud. It also study and assess the well configurations and pilot operating strategies designed for the thermal pilots. A sector model was constructed and calibrated, then used to select a well concept for the LOSF pilots. Seventeen different pilot concepts were considered during the selection process. The well configuration and operating strategies were driven to observe a quicker steam response in the first pilot. A number of sensitivities were conducted to develop a better understanding of the effects of the various reservoir factors.
A comprehensive study was then carried out to recommend a phase development approach for full-scale field development and establish a methodology for a full-field LOSF forecast. Full Field compositional model was built in thermal reservoir simulator and was then successfully history matched with seven components equations of state (EOS). A phased development approach was then proposed for full-scale field development. The initial development will focus on the mid-dip areas with higher remaining oil saturations and a thicker oil column. After establishing production in the mid-dip flanks, development could proceed to the crestal areas, which have lower oil saturations and would likely result in higher steam/oil ratios (SORs).
Ahmadi Reservoir is one of the Reservoirs producing in the Bahrain Field. It has been producing for more than eighty years. Ahmadi is a tight carbonate Reservoir that belongs to the Wasia Cretaceous group. It consists of two main limestone units which are AA and AB. Like most Carbonates in the Middle East, Ahmadi production is dominated by secondary permeability which means that the reservoir has a dual exponential type Curve. Dual exponential in Ahmadi means a high flush initial production period and then a longer period of stabilized production.
Because of this behaviour, using conventional methods to monitor reservoir performance could be misleading. Hence, a new parameter was created to make sure that reservoir performance monitoring accounts for production in a more representive way. This parameter was called Normalized Production Index.
Normalized Production Index has been used to analyse reservoir performance in Ahmadi Reservoir as it accounts for both the flush rate and the stabilized production rate of wells. This parameter helps monitor and observe reservoir performance as it effectively identifies low and high productive areas, and hence leads to better decisions during reservoir development planning.
In this study, a Normalized Production Index of more than 246 wells was considered. These wells vary in area, dip direction, trajectory, and Horizontal length. The objective was to determine the most effective way of these to maximise production in Ahmadi.
Based on the analysis done using Normalized Production Index, it was found that the average oil production for horizontal wells is more than double that of a vertical/directional well. It was also found that wells oriented in an up-dip direction of the structure are performing better than wells oriented in a down-dip direction of the structure in some areas. These conclusions were considered in managing the reservoir. Some actions were taken based on these conclusions and resulted in positive performance, which verified the effectiveness of the Normalized Production Index.
The sandstone facies of Wara formation designated as Ac zone in the Bahrain Field belongs to the Wasia group of the Middle Cretaceous age.
The reservoir has been characterized in three distinct geographical areas of sand distribution based on varied depositional systems, resulting in sands with differing orientation, texture and thickness. The reservoir varies in thickness between 5 and 60 ft and is composed of a series of discontinuous high porosity, high permeability sandstone lenses, sealed above and below by thick competent marine shales.
This paper addresses the variability of the reservoir and the connectivity with the underlying Mauddud reservoir which consequently determined the drive mechanisms.
The original oil in place of Wara sandstone was calculated deterministically using a 3D geological model and incorporated both Geophysical and Petrophysical models. Initial water saturation was calculated from capillary pressure data with net sand cut offs applied. The discontinuity of the sands has resulted in individual sand bodies with variable oil water contacts. Thinner sand bars and channels in the northern area of the Bahrain Field produce by depletion drive. Juxtaposition with the underlying Mauddud reservoir occurring across the faults allows communication with Mauddud gas cap in the Central area which results in the gas drive. Water drive is the main mechanism in the South channel.
Recent log data acquired from new wells has improved our knowledge of this reservoir and explains the different oil-water contacts with the varying drive mechanisms. This improved understanding has resulted in a new development strategy to maximize recovery with infill drilling and possibly Enhanced Oil Recovery (EOR).
The Bahrain Oil Field was the first oil discovery in the Gulf Region in 1932 and is now in a mature stage of development. Crestal gas injection in the oil bearing, under saturated, layered and heavily faulted carbonate Mauddud reservoir has continued to be the dominant drive mechanism since 1938. Thirty eight 40 acre 5-spot waterflood patterns were implemented from 2011 to 2012. These patterns were located in both the South East and North West part of the Mauddud reservoir with a maximum injection rate of 80,000 bbl/day. With less than 10% PV water injected as of December 2012, premature water breakthrough was observed in most of the producers. Rapid water breakthrough in Mauddud A (Ba) is attributed to presence of high permeability vugs and layers resulting in water cycling and poor sweep in the matrix leaving bypassed oil. Following recommendations from the 2013 partner Peer Assist, the South East and North West waterfloods have been converted from pattern to peripheral with downdip wells providing water injection. Peripheral re-alignment has arrested the production decline, reduced water cut and stabilized production.
Surveillance data such as bottomhole pressure data, production logs, reservoir saturation logs, temperature logs and tracer data form the basis of understanding waterflood performance. Additionally, an array of analytical tools were used for diagnosis and analysis. Amongst the diagnostic tools, the Y- function helped to understand water cycling and sweep; the modified-Hall plot assisted in understanding the high-permeability channel or lack thereof and the water-oil-ratio (WOR) provided the clue on fluid displacement. Additional plots such as the "X" plot, decline curve, Cobb plot, pore volume injected vs. recovery, Jordan plot, and Stagg's plot were generated to gain insight on the waterflood.
Based on the waterflood analysis, a field study was initiated in December 2016 by shutting more than 80% of water injection followed by complete shut-in in September 2017. The purpose was to reduce the water cut, improve production taking advantage of gravity drainage effect of gas injectors located up dip of waterflood areas. The implementation of water injection shut-in is still ongoing in the Bahrain Field and pressure/production performance is being closely monitored. Improved production performance is observed following water injection shut-in.
This study underscores the importance of modern analytical tools to diagnose and analyze waterflood performance. This understanding also paves the way for much improved learning to take appropriate actions and help devise long-term reservoir management strategy.
The unexpected response of the Mauddud water flood project led to a detailed review of the petrophysical and geological aspects of this mature cretaceous carbonate reservoir. With almost 2,000 wells, more than 1,000 of which were recently drilled and three cored, the review assessed an extensive data base of openhole, production, saturation log, and historical geological data. The findings resulted in an improved understanding of this reservoir, which historically had been described both as homogenous - fractured and heterogeneous - layered. An understanding of Mauddud's key geological features, their formation, and a link to the observed petrophysics provided the key to developing an innovative permeability transform from resistivity logs, which explained the reservoirs response to the water flood project. With production permeability up to fifty times the measured matrix permeability from core, porosity log derived permeability had failed to reflect the fluid production observed. The adoption of a saturation and production based method provided a useable permeability profile that appeared to explain the observed well and pattern production behavior of the water flood. The new permeability profile also explained both historical fluid behavior and other Enhanced Oil Recovery (EOR) projects, and has since been universally adopted for the reservoir. The permeability estimation technique, which uses resistivity log data, was tested in another infield reservoir with success, and it is thought that the technique has general applicability across many Middle East carbonate reservoirs.
The Bahrain Field, being the first oil discovery in the gulf region in 1932, is now in a mature stage of development. Crestal gas injection in the Mauddud reservoir has continued to be the strongest driving mechanism since 1938. Over the last five years, gas injection and fluid production rates have grown three folds with expanded drilling, workovers, and high volume lift activities. However, there are significant opportunities to increase oil production and optimize gas injection.
An Immiscible-Water-Alternating-Gas injection (IWAG) process was carried out on two composite samples extracted from the Mauddud reservoir of the Bahrain Field. The resulting production and pressure profiles were history matched by using hysteresis and three-phase relative permeability modeling options. Representative relative permeability and capillary pressure curves with the associated hysteresis and three- phase relative permeability parameters were obtained by history matching the experimental IWAG flood results. The history match was carried out by generating the hysteresis parameters and relative permeability curve sets. Experimental results, including two-phase water/gas flood steady state and unsteady state results, were honored to the degree possible. In both composite samples, the IWAG process showed incremental recovery compared to the base case water and gas injection cases. The incremental recovery obtained (above 10% PV) was largely due to the reduction of gas relative permeability during three-phase flow. A maximum trapped gas saturation of 23% was used to history match the core-flood results.
A sector model of the Mauddud reservoir was run using the relative permeability and hysteresis model parameters obtained from the history matching of the composite core-floods. A water and gas flood base case was run and compared to the IWAG sequence. The IWAG process showed incremental recovery compared to the base case water injection. In the up-dip pattern where the water saturation is low, IWAG recovers 3% more than base case gas injection, while gas injection recovers 5% more than the IWAG sequence in the down-dip pattern where water saturation is higher.
The objective of introducing the Immiscible Water Alternating Gas process (IWAG) in Mauddud was to reduce gas production by controlling the mobility during the three-phase flow. Incremental oil, compared with gas and water injection was also to be evaluated. Three IWAG pilots were introduced after an extensive study on optimum locations. Two inverted 5-spot patterns and one line drive pattern were selected; each pattern is around 40 acre spacing, targeting Mauddud B interval. The original Water Alternating Gas (WAG) ratio was designed to be 1:3 (Water: Gas) and the WAG period was originally designed to be from three to six months based on simulation work. WAG ratio and duration optimization were subject to performance. After one year of cyclic injection, both inverted 5-spot patterns showed lack of response to the WAG cycles. In one of the two latter patterns, the water cycles critically affected oil production. In the line drive pattern, the WAG cycles initially showed a favorable response. After one year of injection, water and gas overcame oil production, leading to higher oil decline and the termination of the pilot due to confinement and operational issues.
Approximately 20% of all oilwells in the world use a beam pump to raise crude oil to the surface. The proper maintenance of these pumps is thus an important issue in oilfield operations. We wish to know, preferably before the failure, what is wrong with the pump. Maintenance issues on the downhole part of a beam pump can be reliably diagnosed from a plot of the displacement and load on the traveling valve; a diagram known as a dynamometer card. We demonstrate in this paper that this analysis can be fully automated using machine learning techniques that teach themselves to recognize various classes of damage in advance of the failure. We use a dataset of of 35292 sample cards drawn from 299 beam pumps in the Bahrain oilfield. We can detect 11 different damage classes from each other and from the normal class with an accuracy of 99.9%. This high accuracy makes it possible to automatically diagnose beam pumps in real-time and for the maintenance crew to focus on fixing pumps instead of monitoring them, which increases overall oil yield and decreases environmental impact.