This paper illustrates the importance of classification and identification of rock types within integrated reservoir characterization studies. The goal is not to present a new classification scheme, but to draw attention to the benefits of a classification that provides the basis for populating a geo-cellular model with key attributes (porosity, permeability, saturation). Rock type, as derived from an integration of core examination, routine and special core analysis and wireline logs, and conditioned with well tests, facilitates geologically reasonable property prediction. The study concludes that a single classification scheme is impractical for all aspects of geological modeling. This work stems from a comprehensive reservoir description study of the Jurassic Arab C and D reservoirs of the Dukhan field. Core descriptions, routine core analysis, and visual examination of log data form the basis for recognition of an initial classification internally named ResFacs (Reservoir Facies). Because ResFacs originate from core, volume fractions and distribution are readily derivable from a cycle-based, sequence stratigraphic interpretation. Mineralogical and depositional trends of ResFacs form an initial conditioning parameter for models. This core-based classification is also used in all routine and special core analysis (SCAL) to segregate rocks of differing reservoir quality. It forms the common variable between all other classifications. SCAL data reveals reservoir quality trends that are not resolvable from core description and routine analyses alone. Most important were trends in fine-grained, muddy limestones and very coarse-grained lime grainstones. MICP data and saturation height modeling reveals a small volume of low porosity lime mudstones with such fine pore systems that they are unlikely to have been filled with hydrocarbons. At the other end of the spectrum, SCAL data and petrography reveal a class of coarse grainstones with point of contact cements that exhibit extremely high permeability. These data are used to modify the ResFac classification for use in calibration of well logs. Log-derived rock types, referred to as Petrophysical Reservoir Facies (PRFs) have been established to increase input data density for property distribution in geological models. As with many oilfields, historical SCAL and routine core analyses of variable quality are available. In order to make use of these data, samples were classified within the ResFac scheme. In addition, 100 representative samples were selected for further analysis (MICP, NMR, petrology, and porosity-permeability measurement at ambient and overburden conditions). This dataset provides a means of resolving pore systems by rock type and allows incorporation of historical data analyzed under variable laboratory conditions. The ResFac classification scheme is impractical for numerical modeling. Accordingly, ResFacs were consolidated based on texture, mineralogy, and rock type with unique saturation height functions. The final input into flow simulation models is termed Reservoir Rock Types (RRTs). These RRTs are used for property prediction, and calibration occurred with static data (e.g., initial water saturation from logs) and dynamic data (e.g., well test permeability-thickness and profiles from production logging tools). Rigorous rock description and comparison to measured static and dynamic data ensure that models based on RRTs describe fluid distribution and fluid flow capability.
The proportion of new wells requiring sand control is increasing, and choosing the most economic sand control system from the available options is a central component in field development planning. The choice of sand control system depends on a number of factors such as production and sand control performance, reserves recovery, reliability, ease of installation and life cycle economics. Logistical and HSE issues are also becoming increasingly important, especially in areas with limited support infrastructure. A key input to the process of sand control system selection is data on how the various systems compare in a given environment. Ideally, this comparison should be made over time in order to properly compare the long term performance and reliability. This data can only be obtained by analyzing existing installations equitably and objectively. The Mokoko-Abana field is situated offshore Cameroon. It is a mature heavy oil field with unconsolidated formations that require sand control from the onset of production. A wide variety of sand control solutions have been used in this field, although with varying levels of success and performance. Cased hole internal gravel packs (IGP), milled casing openhole under-reamed gravel packs (MCGP) and cased hole frac-packs (CHFP) have been used in vertical wells. Prepacked stand-alone screens (PPSAS), openhole gravel packs (OHGP) and openhole expandable sand screens (OHESS) have been used in horizontal and highly deviated wells. Each of the completion options now has several years of production history. This allows the initial performance and the performance over time to be modelled and compared. The wells chosen for study were in the same sand body with as near perfect installation as possible. The MCGP had relatively good performance as did the CHFP, unfortunately however the CHFP fractured into a water bearing leg and only added water cut. The PPSAS had initially low mechanical skins, but its performance declined quickly. The OHGP had higher initial skins but the rate of production decline is much slower. The OHESS had a very low initial skin with no impairment over the five year production period. SPE 946511contains background information on the Mokoko-Abana field, and looks at the productivity performance of the PPSAS, OHGP and OHESS techniques on initial completion and after two years of production. This paper follows on from SPE 94651 and examines the operational, productivity, reliability and economical aspects of the completion techniques over five years or more of production. Introduction A comparison of the performance of sand control completions in the Mokoko-Abana Field was carried out in 2004 and 2005. This compared three wells completed on the same oil sand with essentially the same hole size, similar drilled trajectories, similar drilling mud, the same rig and with largely the same personnel. All were successfully executed and can be considered as fair and reasonable comparisons. Each well had(then) at least two years production history. Differences in reservoir properties, artificial lift method and minor differences in fluid characteristics were modelled and backed out.
Over the last decade, horizontal drilling has played a significant role in the development of the Dukhan field in Qatar. Optimal placement of high-angle and horizontal wells has ensured economic hydrocarbon production in the Arab oil reservoirs. In the Arab C reservoir interval, stratigraphic layers are generally thin and exhibit a high degree of lateral variation in rock properties and low to medium permeability. Horizontal producers with long lateral sections have increased ultimate recovery by providing greater penetration of oil columns above oil water contacts and by tapping attic oil and isolated reservoir compartments. Sweep efficiency has also been improved through horizontal well waterflood programs. Advances in rotary steerable drilling and logging-while-drilling (LWD) technologies for horizontal wells provide new types of data that can be used for improved reservoir characterization and geologic modeling. LWD sensors are used at Dukhan to acquire real time petrophysical measurements and LWD image logs are now routinely acquired along with conventional triple combo logs (density/neutron/resistivity). A specialized workflow was developed to utilize the LWD image data in log interpretation. This workflow consists of interpretation modules that can be used to define formation bed boundaries and quantify formation property variations along horizontal wellbores. These definitions of 3D bedding structure data and formation properties are then used to condition the geologic model structure and update cell properties. Image logs and petrophysical interpretation results from several horizontal wells will be presented. Comparisons with offset vertical wells are made to illustrate the added value of using horizontal well data in reservoir characterization. Significant uplift in geological modeling is also achieved by incorporating lateral property variation identified through horizontal well petrophysical evaluations. Introduction Dukhan Field, discovered in 1939, is one of the major oil fields in the Middle East region. The first discovery wells were based on field mapping of the Dukhan anticline (Trabelsi et al., 2009, Stephens et al., 2009). The field forms a north to southeast trending anticline that is 70 km long and 8 km wide (Figure 1A). The anticline culminates in four distinct domes, which roughly correspond to the major divisions of the field. These are, from north to south, the Khatiyah, Fahahil, Jaleha, and Diyab sectors (Figure 1B). A series of extensive studies have been done to characterize the environments of deposition and to define a consistent sequence stratigraphic framework (Figure 2). Production of the Arab C and D reservoirs started in 1949 and has progressed through various phases of the oil field development.
Summary Choosing the most economic sand-control system from the available options is a central component in field development planning. The choice of sand-control system depends on a number of factors such as production and sand-control performance, reserves recovery, reliability, ease of installation, and life-cycle economics. Logistical and health, safety, and environment (HSE) issues are also important, especially in areas with limited support infrastructure. A key input to the process of sand-control-system selection is data on how the various systems compare in a given environment. Ideally, this comparison should be made over time to compare properly long-term performance and reliability. These data can be obtained only by analyzing existing installations fairly and objectively. The Mokoko-Abana field is situated offshore Cameroon. It is a mature heavy-oil field with unconsolidated formations that require sand control from the onset of production. A wide variety of sand-control solutions have been used in this field, with varying levels of success and performance. Cased-hole internal gravel packs (IGPs), milled-casing openhole underreamed gravel packs (MCGPs), and cased-hole frac packs (CHFPs) have been used in vertical wells. Prepacked standalone screens (PPSASs), openhole gravel packs (OHGPs), and openhole expandable sand screens (OHESSs) have been used in horizontal and highly deviated wells. Each of the completion options now has several years of production history. This allows their initial performance and their performance over time to be modeled and compared. The wells chosen for study were in the same sand body with an installation as close to perfect as possible. The MCGP had relatively good performance, as did the CHFP; unfortunately, however, the CHFP fractured into a water-bearing leg and only added water cut. The PPSAS had initially low mechanical skins, but its performance declined quickly. The OHGP had higher initial skins, but the rate of production decline was much slower. The OHESS had a very low initial skin with no impairment over the 5-year production period. Mason et al. (2005) provide background information on the Mokoko-Abana field and look at the productivity performance of the PPSAS, OHGP, and OHESS techniques on initial completion and after 2 years of production. This paper follows on from that work and examines the operational, productivity, reliability, and economical aspects of the completion techniques over 5 years or more of production. Introduction A comparison of the performance of sand-control completions in the Mokoko-Abana field was carried out in 2004 and 2005. This study compared three wells completed on the same oil sand with essentially the same hole size, similar drilled trajectories, similar drilling mud, the same rig, and largely the same personnel. All were successfully executed and can be considered as objects of a fair and reasonable comparison. Each well at that time had at least a 2-year production history. Differences in reservoir properties and in artificial lift method and minor differences in fluid characteristics were modeled and compensated for. The end result was a derived mechanical-skin value for each completion system. The derived skin after 2 years' production for the PPSAS was +29.5, for the OHGP was +10.8, and for the OHESS was approximately zero. The Mokoko-Abana OHESS deployment was one of the earliest expandable-sand-screen (ESSO) installations (number 26 out of 400 to date from various vendors), and it is now possible to look at the completion performance of this technology over several years. The best sand-control completion is the one that is technically suited for the particular application and then provides the user with the best value over the life cycle of the well. Installation cost, productivity, and reliability (both installation and production risk) are all important factors in achieving this. Meaningful comparisons are usually available only in mature fields, where different sand-control completions have been attempted over different time periods. Skin data over time have not been studied in detail to date; most studies report skin data within a short time period following completion installation. This paper seeks to begin to address this issue and to provide operators with a balanced and objective comparison among the systems carrying on from the original Mason et al. (2005) study.
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