Al-dhufairi, Mubarak Audah (Saudi Aramco) | Al-yateem, Karam Sami (Saudi Aramco) | Duthie, Laurie (Saudi Aramco) | El-Kilany, Khaled Ahmed (Saudi Aramco) | Elsherif, Tamer Ahmed (Schlumberger) | Ahmed, Ramy (Schlumberger)
Increases in well complexity and stimulation challenges have led to more complicated stimulations. The challenge that consistently arises after conceptually designing the treatment is how to determine the zonal coverage and evaluate the stimulation, especially in extended reach wells in carbonate reservoirs. Significant effort has been spent on using modern technologies to qualitatively evaluate zonal coverage and estimate the skin factor evolvement after the treatment. No work has yet answered the following question: How does matrix acidizing alter near-wellbore permeability and affect the zonation of the wellbore when treating carbonate reservoirs?
In long horizontal wells that are drilled in carbonate formations, it is believed that wormholing significantly alters the near-wellbore apparent permeability. Nevertheless, methods to estimate the change in permeability resulting from a matrix treatment are not known, and usually the change is accounted for in simulators by assigning a very low skin value. Other work conducted in carbonate reservoirs using pressure transient analysis (PTA) techniques has shown that applying a change in permeability is necessary to obtain a type-curve match.
This paper presents an innovative workflow and algorithm to estimate the changes in the critical matrix rock properties and how to incorporate these changes into further simulation. The algorithm integrates the while drilling mobility data, open hole porosity logs, pressure transient data, distributed temperature survey data, and production logging data to verify the accuracy of the model by using the flow rate as the control parameter for iterations.
A case study shows how we could derive a flow profile for the pre-stimulation stage, optimize matrix stimulation treatments in real time according to the formation response and diversion efficiency, define reservoir zones that are contributing to flow before and after the treatment, and finally, estimate new values of permeability and skin to be utilized in post-treatment reservoir simulations.
It is very challenging to measure formation pressure in the low mobility formations of Eastern Desert, Egypt. The measured mobilities ranged from 0.01 to 5 mD/cP; making the acquisition of reliable formation pressure with conventional pretesting very difficult. Many pretests end up being recorded as ‘Dry', ‘Tight' and ‘Supercharged'. However, by exploiting the extreme limits of new generation formation testers such as low volume and relatively lower rates, we were able to overcome these difficulties and record valuable formation pressures.
The electromechanically controlled formation tester is specifically engineered for only pressure and mobility testing as opposed to multifunctional formation tester tool that also collects samples. The two important distinctions of this tool are an electromechanically controlled pressure pretest system that enables precise pretest volume and rate. This is in contrast to the hydraulically driven pretest mechanisms in conventional tools. Secondly, because the tool is devoted only to pretesting, it has a very small flowline volume with very tight mechanical construction. The required decompression volume is much smaller than conventional tools, brings new efficiency to the formation pressure testing process by significantly reducing both the time and risk involved with wireline formation testing operation.
The operating guidelines is prepared to recognize pressure measurement challenges in low mobility formations, it may assist engineers to identify the problems and take corrective measures by altering pretest volume and rate. Correct practice of taking right volume and rate may bring value to pretests whereas inexperience of pressure measurement in low mobility formations may cause significant damage to the data quality. Herein we have presented examples of good quality pretests changing into ‘Dry' or ‘Tight' by taking high volumes and also conversely the ‘Dry' or ‘Tight' pretests converting into good quality by optimizing pretest volumes.
The Arta fields of Egyptian Eastern Desert are operated by Petrodara, a joint venture of Transglobe Energy and Egyptian General Petroleum Corporation (EGPC). The main producing horizon is the Nukhul and formation pressure measurements are critical in this poorly sorted conglomerated marl in order to understand and model depletion. However, low permeability and high viscosity oils contributed to a very low mobility environment that presented considerable challenges to Wireline Formation Tester (WFT) tools. Extensive testing programs resulted in an excessive amount of tests that were unusable, being classified as ‘dry', ‘tight' or ‘supercharged'. This low mobility environment also complicated the requirement for PVT samples acquired with the WFT tools. Normal testing operations resulted in very high drawdowns that sampled below formation pressure and caused emulsions with the filtrate of the water based drilling fluid.
In this paper we discuss how the Operator and the Service Company combined to employ fit for purpose WFT techniques to acquire accurate formation pressure data and PVT quality oil samples. Most of our discussion will be based on understanding the dynamics of pretesting in low permeability formations and how the optimal tool and pretest design can produce results where previous attempts have failed. Specifically we consider the newest ‘pretest only' WFT that provides very fine control over pretest rate and volume and allows precise test design that is not possible with conventional WFT tools. Additionally, we demonstrate the application of best practices and lessons learned from worldwide sampling operation to acquire PVT quality heavy oil samples.
The Arta field in the Egyptian Eastern Desert produces mainly from the Nukhul Formation that is characterized as a complex, thin-bedded sequence with heterogeneous laminated siltstone. Typical reservoirs show low-to-average permeability, low temperatures and moderately heavy oil in the 17-24 degree API range. The Nukhul Formation represents the early rift sequence of the Gulf of Suez rift basin. It is underlain by the Thebes Eocene carbonates of the Pre-Rift sequence and overlain by a thick succession of predominantly fine-grained marine clastics of the synrift Rudeis Formation. The Nukhul Formation in Arta field is subdivided into two sections: the Lower Nukhul, which is composed mainly of conglomeratic sandstone with some shale and limestone streaks and the Upper Nukhul which comprises a vertically stacked conglomerate, occasionally sandstone, and sandy limestone lithofacies. The limestone facies is more common within the Upper Nukhul and it represents a tidal-dominated estuarine facies within marginal marine realm deposited in a low to moderate energy setting. The deposition of Nukhul formation records a finning-upward rhythmic sedimentation represented by sequences of tidal channel and estuarine channel fill sandstone. These sediments were deposited on the paleo-low relief areas of the Thebes unconformity. (Edelman 2013)
The Lower Nukhul has higher porosity and permeability, which is supported by water injection and generally does not require stimulation. The upper Nukhul has porosity ranging from 5 to 18% with an arithmetic average of 13% and a mean of 12%. Permeability ranges from 0.003 mD to 12.8 mD with an arithmetic average of 1.5 mD and a mean of 0.6 mD. The reservoir requires hydraulic fracture stimulation to be economically productive.
Bahuguna, Ajay (Oil & Natural Gas Corp. Ltd.) | Ahmed, Ramy (Schlumberger) | Ahmed, Mohamed Elbadri (Schlumberger) | Vazquez, Maria Leticia (Schlumberger Logelco, Inc) | Shaheen, Tarek | Sutrisno, Hermawan Joko
Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has several wells that have commingle production from the Aradeiba, Bentiu-1 and Bentiu-2 formations. These formations are highly variable in terms of the reservoir properties, oil types and pressure regimes. Because of the contrast properties of different layers, the water cut phenomenon is relatively fast and severe which hampers the productivity and ultimate recovery of the individual well as well as the field.
For effective Reservoir Management and to limit the declining trend of the field, Water Management Techniques are applied in some of the wells of this field. Information obtained in the process was used for reservoir model calibration, well productivity prediction, low productivity diagnosis, and generation of new drainage points and remedial action for water management.
This paper discusses the technical details of three cases corresponding to the wells Munga-XX and Umm Sagura South-XX (USS-XX) and Munga-XY in which, a multidisciplinary approach has been implemented in order to determine depletion profile, produced oil and remaining reserves, locate any "by-passed?? oil zones, determine oil and water contributions from each zone and shut off the excess water production while maintaining or increasing oil production.
The source of water entry was identified in multi-rate production logging using Production Services Platform and electrical probes through Y tool-ESP completion. Vx meter was carried out at surface to real time monitoring the well production during the production logging survey. The well depletion profile was determined using Cased Hole Formation Resistivity (CHFR*) tool. A multidisciplinary team processed and interpreted the logging data and based on the results remedial jobs were carried out
The general outcome of the remedial jobs based on this approach was a considerable reduction in water production in both Munga-XX and USS-XX wells as well as oil production gain, making this a successful job.