The objective of this work is to characterize the fault system and its impact on Mishrif reservoir capacity in the West Quran oil field. Determination and modelling of these faults are crucial to evaluate and understanding fluid flow of both oil and water injection in terms of distribution and the movement. In addition to define the structure away from the well control and understanding the evolution of West Qurna arch over geologic time.
In order to achieve the aim of the work and the structural analysis, a step wise approach was undertaken. Primarily, intensive seismic interpretation and building of structure maps were carried out across the high resolution of 3D-seismic survey with focusing on the main producing Mishrif reservoir of the field. Also, seismic attributes volumes provided a good information about the distribution and geometry of faults in Mishrif reservoir. The next step, it constructs 3-D fault model which will be later merged into the developed 3D geological model. West Qurna/1 oil field situated within the Zubair Subzone, and it is structurally a part of large anticline towards the north. The observation of seismically derived faults near Mishrif reservoir indicated en-echelon faults which refer to strike-slip tectonics along with extensional faults. The statistic of Mishrif interval faulting indicates a big number faults striking north-south along western wedge of anticline. The seismic interpretation, in combination with seismic attributes volumes, deliver a valuable structural framework which in turns used to build a better geological model.
In this paper, the work demonstrates a better understanding for the perspectives on the seismic characterization of the structural framework in the Mishrif reservoir, and also for similar heterogeneous carbonate reservoirs. Further, this work will ultimately lead to improve reservoir management practises in terms of production performance and water flooding plan.
To date, our feasibility studies [CMTC-502487-MS and SPE-190163-MS] of the Gad and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process for the South Rumaila oil field have considered using Carbon Dioxide gas injection to enhance recovery from the field. As availibiulity of CO2 is limited and its cost considerable it might be also feasible to use natural gas,, Associated Produced Gas (APG) as an alternative solvent to enhance oil recovery with this process. In the study, efficiency of APG vs. CO2 is compared for the South Rumaila oil field.
In the study, the GDWS-AGD process installation includes 20 vertical APG injection wells are drilled to the top of the reservoir to build a gas cap in the oil pay zone. In addition, eleven horizontal oil-producing wells are placed at the bottom of the oil pay zone with six horizontal water drainage (sink) wells below the oil-water contact (OWC). The two horizontal leg installation may be made from a vertical well with 7-casing dual-completed (from two kick-off points) in the oil payzone and in the bottom water (below OWC) with two horizontal well legs and the two 2-3/8 inch tubings in each well. In a dual-tubing design of the process the two horizontal well legs produce independently. If only one tubing is used production from the water sink well is hydraulically isolated inside the vertical well by a packer. In either design, the water sink well is operated with a submersible pump.
In this study, the GDWS-AGD process with APG is considered for the upper sandstone member/South Rumaila Oil Field, located in Iraq to improve oil recovery. The Rumaila field has an infinite acting-aquifer with very strong edge water drive. In the GDWS-AGD, the bottom water drainage would not only reduce water cut and water cresting, but would also significantly reduce the reservoir pressure, resulting in improving gas injectivity. The study shows considerable improvement with the GDWS-AGD process - oil recovery increased from 76% by CO2 to 83% by APG and water cut was readily controlled resulting in more rapid reduction with APG (from 98% to less than 5%) than that with CO2 in all horizontal oil producers. The results show that the use of APG gas alternative for the GDWS-AGD process not only improves water-cresting control due prompt reduction of water cut, but also enhances gas injectivity and significantly improves oil recovery.
Forging an authentic and meaningful brand for major projects in complex and challenging regions is an under-rated tool for managing risk—but not at the Rumaila oilfield in Southern Iraq. Iraqi forces are preparing an operation to consolidate control of an area near the Iran border to be used for the transit of Iraqi oil, two officials said, highlighting concern about mountainous terrain where two armed groups are active. Iraq plans to use drones to monitor and protect its oil export and production pipelines from the first quarter of 2018, an oil ministry spokesman said on 18 December.
Africa (Sub-Sahara) United Hydrocarbon International finished drilling the Belanga North-1 exploration well located in Doba basin in southern Chad. The well was drilled to a total depth of 1392 m, and encountered three oil-bearing sand intervals--two in the targeted Upper Cretaceous "YO" sands and one in an untested shallower sand. United Hydrocarbon (100%) is the operator. Asia Pacific China National Offshore Oil Corporation discovered natural gas in the Qiongdongan basin, South China Sea. Well Lingshui 17-2--located in the east Lingshui sag portion of the basin at an average water depth of 1450 m--was drilled and completed to a depth of 3510 m. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
Africa (Sub-Sahara) Oil samples have been recovered in the FAN-1 exploration well, being drilled offshore Senegal. Elevated gas and fluorescence were encountered in a shallow secondary target, and the presence of oil was confirmed by an intermediate logging program. Oil samples from thin sand were collected by a wireline formation tester for further analysis. The well will be deepened to a planned total depth of approximately 5000 m. Cairn is the operator (40%), with partners ConocoPhillips (35%), FAR (15%), and Senegalese national oil company Petrosen (10%). A drillstem test of BG Group's Mzia-3 well--located in Block 1, offshore southern Tanzania, at a water depth of around 1800 m--reached a maximum sustained flow rate of 101 MMscf/D of natural gas. The Mzia prospect is a multilayered field of Upper Cretaceous age with a gross gas column estimated at more than 300 m.
Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Africa (Sub-Sahara) ExxonMobil will drill its first exploratory well offshore Liberia this month, the company announced on 18 October. A deepwater well is planned on the Liberia-13 Block, which is about 50 miles off the coast of the West African country. Solo Oil plans to spud the Ntorya-2 appraisal well in Tanzania next month. The drilling pad is a mile southwest of the 2012 Ntorya-1 discovery well, which was tested at rates of 20.1 MMcf/D of gas and 139 B/D of condensate. An independent report estimated the discovery to hold 153 Bcf of gas in place, of which 70 Bcf is considered a gross best-estimate contingent resource. A gross best estimate of more than 1 Tcf of gas in place has been made for the Ntorya prospect as a whole, in which the company has a 25% interest. Asia Pacific BP has decided to abandon drilling plans in the Great Australian Bight offshore southern Australia, an area in which prospective drilling has long been contested by environmentalists.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alkhamis, Mohammed M. (Missouri University of Science and Technology) | Mutar, Rusul A. (Ministry of Communications and Technology)
Lost circulation is a complicated problem to be predicted with conventional statistical tools. As the drilling environment is getting more complicated nowadays, more advanced techniques such as artificial neural networks (ANNs) are required to help to estimate mud losses prior to drilling. The aim of this work is to estimate mud losses for induced fractures formations prior to drilling to assist the drilling personnel in preparing remedies for this problem prior to entering the losses zone. Once the severity of losses is known, the key drilling parameters can be adjusted to avoid or at least mitigate losses as a proactive approach.
Lost circulation data were extracted from over 1500 wells drilled worldwide. The data were divided into three sets; training, validation, and testing datasets. 60% of the data are used for training, 20% for validation, and 20% for testing. Any ANN consists of the following layers, the input layer, hidden layer(s), and the output layer. A determination of the optimum number of hidden layers and the number of neurons in each hidden layer is required to have the best estimation, this is done using the mean square of error (MSE). A supervised ANNs was created for induced fractures formations. A decision was made to have one hidden layer in the network with ten neurons in the hidden layer. Since there are many training algorithms to choose from, it was necessary to choose the best algorithm for this specific data set. Ten different training algorithms were tested, the Levenberg-Marquardt (LM) algorithm was chosen since it gave the lowest MSE and it had the highest R-squared. The final results showed that the supervised ANN has the ability to predict lost circulation with an overall R-squared of 0.925 for induced fractures formations. This is a very good estimation that will help the drilling personnel prepare remedies before entering the losses zone as well as adjusting the key drilling parameters to avoid or at least mitigate losses as a proactive approach. This ANN can be used globally for any induced fractures formations that are suffering from the lost circulation problem to estimate mud losses.
As the demand for energy increases, the drilling process is becoming more challenging. Thus, more advanced tools such as ANNs are required to better tackle these problems. The ANN built in this paper can be adapted to commercial software that predicts lost circulation for any induced fractures formations globally.